By the way, because of the nature of the talk which is very technical, in case I use a term in my presentation over the next 20-25 minutes that completely goes over your head, just raise your hand and I will ignore you. [Laughter] No. Of course not. Of course not.

In case there is a point like that we will address it right then, not in the context of a discussion but just in the context of an explanation.

Now the term reserves means so many things to so many people. That's why it's very very important that we all reach a common understanding about some of those terms that are being used.

Mr. Abdul-Baqi very competently explained the most important one which is the oil initially in place. That's the tank that we're talking about. How much oil do we have in the subsurface? And all the definitions that we're talking about are the standard definitions used by the three leading organization which is the Society of Petroleum Engineers; the World Petroleum Congress; and AAPG which is the American Association of Petroleum Geologists. As I said, the most critical one is reserves because we have to understand what we mean by reserves.

In plain English it's oil that can be recovered commercially with current technologies.

There the key word is commercially and current technologies. Of course there is another embedded assumption in that term, and that is with the current cost structures.

Of course the industry typically uses three common terms. One is proved, the other is probable, and the third one is possible. The one that's common to everybody and that's the one that's reported, that's the basis of the one thousand billion barrels that Mr. Abdul-Baqi talked about is the proved one which is associated with a 90 percent probability or 90 percent certainty.

Then at the other end of the spectrum is the contingent resources, anything that has an associated probability of less than ten percent, then it's categorized as contingent.

Now I'm going to focus on proved reserves and there is a message here that I want to convey. That message is that overall Saudi Aramco in arriving at its reserves of 261 billion barrels –

Yes, sir?

Question: [inaudible]

Dr. Saleri: Okay, that's more of a commentary. We will comment on that. But the reserves, in case there is any misunderstanding, reserves is the part of the oil that you can commercially recover. So imagine a tank of one thousand barrels. With the current technologies if you only recover 600 then your recovery is 60 percent so your reserves that you book is 600 barrels. So that's the definition of what we consider in the industry as proved reserves.

The company as part of its practices in determining its 261 billion barrels follows all the SPE and WPC standards with a very conservative interpretation, and that's something that I would like to underscore. What do I mean by that?

Specifically there is one item which is shown in yellow over there, on the screen, and that is the enhanced oil recovery methods. Commonly, most of the companies apply enhanced oil recovery methods and project their impact in the ultimate recovery of oil. It's part of their reserves. Saudi Aramco neither in its proved reserves nor in its probable reserves takes any credit for any present or future EOR, and that's a significant distinction. That again is a reflection of the company's very conservative approach to managing its reserves.

I will dwell on this theme, because it's a very central one, throughout the presentation.

I think it would be helpful to talk about the life cycle of a field and how it relates to some of those things --oil in place and reserves, probably or possible, all of these things. I think this chart is very very helpful.

What I am showing for a typical field is a production rate profile, production versus time. It could be anywhere from 20 years to typically in the case of Saudi Aramco fields, we usually talk about 75 to 100 years plus. We have many fields that are already in production for more than half a century, and I will show some examples of that.

There are two parts to it. The first part is the exploration where you use different techniques and you drill well, you explore and you discover oil. Then you enter the development and production mode. You get the production at a certain level which is known as the plateau, and then you go through an economic, finally bring it down to an economic rate and that's where you end, the end of the field. What's under that curve which is shown by the green area is your reserves, what is recovered from underground.

There are a few things that happen, particularly with the philosophy that Saudi Aramco applies which is a very go-slow type of a process where we extend the lifeline of a field to something like 50, 60, 100 years. When time works in a certain fashion it's certainly very beneficial from a reserves point of view because as time goes on new technologies come in and our overall understanding about what's in the subsurface enhances significantly which has a very important consequence. In fact it has two primary consequences that we need to appreciate. What are these consequences? There are two.

First, what I just said that the certainty of reserves estimates improves with the production life. The more you produce the more you understand. Your confidence level. What was originally considered as possible, low probability, then becomes probably, higher probability. Eventually you go from probable to proved category.

What we were carrying, for instance, our oldest field Abqaiq back in the 1970s was already produced about ten years ago. We were carrying 11 billion barrels and we've already produced two billion more in Abqaiq. So that shows you what happens over a period of time as you're producing the field.

The other thing that happens which is associated with this time line is the fact that new technologies come in, especially advances in IT technologies, seismic, diagnostic technologies, all of those things come in and they certainly add to the recoveries at hand. I think this is a very important point to keep in mind.

I think this is probably a very very central pie chart and it warrants a few seconds of discussion. Essentially what I am showing you is the tank. How big is the tank? As we know it as of January 1, 2004. This is the oil initially in place with all the best technologies that the company has, with all its best knowledge at this time is 700 billion barrels.

How does that distribute itself into different categories? Let's go over them one by one. We have historically produced 99 billion barrels to date. That's only 14 percent. That's only 14 percent of the total tank, and we're not even talking about the expansion of the tank. Remember what Mr. Abdul-Baqi said. We're projecting it to grow from 700 to 900. So I'm not talking about the expansion. I'm talking about the tank the way we know it. Where do we stand? We've only produced 14 percent. The reserves that we're talking about as proved reserves today, the 260 billion barrels that Saudi Aramco reports, is the other shade of green. That's the 37 percent. Yet we have at least another 100 billion barrels that we feel very very confident will be recovered with current technologies and upcoming technologies in the years ahead. That's the possible and probable. Because of the EOR component, because of the new technology component. The company feels very very comfortable about this. So that's another 100 billion.

Then when you look at the contingent resources, that represents a vast opportunity of about 240 billion barrels which is a tremendous opportunity for new upcoming unfolding generation of new technology. So that's not even in the planning stages right now.

Add to it the expansion component that Mr. Abdul-Baqi talked, that we're going to go from 700 to actually 900 billion barrels in oil initially in place because of future discoveries and developmental work. It's very very obvious where we stand
reserves wise.

We believe very comfortably that we're looking very conservatively --again this is the company's approach, very conservatively, upwards of 150 billion barrels --150 billion barrels over and above the 260 billion barrels that we carry as proved reserves right now. That's 60 percent more. And that's the underlying message we want to convey.

Now there are a number of metrics that the industry uses, including ourselves, when we look at reserves as far as the integrity, the quality, and the viability of the reserves. One of the most relevant ones is what is the extent of proved reserves depletion? We have actually 23 active fields right now out of a reservoir portfolio of over 80 fields. I'm only showing some of the key ones and I'm covering the whole spectrum --from the youngest one which is Shaybah with five percent of reserves depletion --that means we have already produced five percent of what we considered proved reserves; and the most mature one, Abqaiq. We've already produced 73 percent. And look at the average age of the portfolio. It's 28 percent, which is fantastic by industry standards. There is no other company that even comes close to reserves depletion state of 28 percent, and this is with
the 260 billion barrels. It's not with the additional potential that we're talking about in the future.

Again, look at Ghawar as a total. It's only at 48 percent. Parts of Ghawar are completely undeveloped. Haradh which is more than three times the size of Prudhoe Bay, it's over three times the size of Prudhoe Bay, it's only ten percent developed. So these are very very important statistics. I know I'm overloading you with some numbers, yet it goes to the essence of the source of the issues that are being discussed.

Another one that's often looked at is what percentage of your reserves, the booked reserves again, is developed. That's 30 used as a metric. In our case it's roughly 50 percent. It's 131 billion barrels to be exact. Again even in this one the company takes a very conservative outlook on those things. We have two giant fields --Manifa and Khurais. These have combined reserves of 41 billion barrels --41 billion barrels. Now both of these fields have put on production in the past. They have produced for years. Currently they are shut in because of low demand. The company in its overall business logic does not see the current need for putting them on production.

But the point here, as far as this particular slide is that that 41 billion barrels is not considered as developed under our statistics. So we take a very very conservative outlook on that again.

Now that I gave you a general number on reserves so we all feel comfortable with the overall architecture we're talking about, the size of the tank, while we're thinking about the future let's address something very very fundamental which is what makes Saudi Aramco so special? Are there distinguishing characteristics? Are there distinguishing principles that set Saudi Aramco away from the rest of the pack? The answer is absolutely positively yes. We are different. We have managed our fields differently and we will manage our fields differently. So any analogies with other fields, with other operators are not necessarily applicable to Saudi Aramco. I'm going to develop on this theme because it's this very theme that drives our plans for the future. Because if we don't understand the past we may not fully appreciate the plans forward.

Now Mr. Abdul-Baqi already talked about the overriding principles of the company and there's a corollary when it comes to reservoir management because that's the heart and soul of the company's operation.

With a bit of exaggeration I would say this is like the Bill of Rights of the reservoirs. Okay? It's intended to be. It's the constitution. It's the principles that govern the management and production and depletion of the reservoirs.

Number one, at the very top, it's maximizing hydrocarbon recovery. We intend to maximize the hydrocarbon recovery.

Number two is reservoir monitoring. We realize that to maximize hydrocarbon recovery you have to emphasize reservoir monitoring, particularly surveillance techniques with state of the art technologies.

Number three is a very important one, again that sets us separate from the rest of the crowd. That is low depletion rates. We produce our reservoirs at very low depletion rates by industry standards.

Number four, we put a significant emphasis on advanced diagnostics. What do I mean by advanced diagnostics? What we mean by advanced diagnostics is intensive computational efforts on modeling so that we understand precisely what's going on 10,000 feet underground, in every foot of the reservoir. That's what we mean. That's why technologies such as seismic, technologies such as reservoir simulation, coupled with the second bullet which is reservoir monitoring. Surveillance is critical so that we achieve the maximum hydrocarbon recovery.

Finally, as a philosophy we apply cutting edge technologies all across. That translates into a continual improvement, into a learning reservoir management model.  

Now I mentioned depletion rates, and I think this is something that everybody relates to. We know some of the fields like Prudhoe Bay, Yibal, I'm glad Yibal was mentioned because it's right there, East Texas, Ekofisk, Forties, Brent. All of you have heard these terms. Look at the typical annual depletion rates. Historical maximums, okay? You would see typically numbers ranging anywhere from four to ten percent. What you would see on the Aramco side is rates like one percent in the case of Abusofa, Shaybah is like that, to the maximum ever. These are not averages. This is the maximum ever annual depletion rate that the company has ever recorded in its 70-year history and that's 4.1. Our typical depletion rate is about two percent.  

Now you're going to say so what? What's going on?

If you produce things slowly you expand the life cycle. And when you expand the life cycle you get the benefits of new technologies. Much better diagnostics, much better way of managing the reservoirs, much better way of navigating against any uncertainties, any surprises. And it has a significant direct business impact.

Now we're talking about diagnostics, and all companies have very superior diagnostics. We're not questioning that at all. But we're also proud of the diagnostics capabilities, particularly in the seismic area, that's giving us a definite edge in better understanding. Just like the Hubble telescope gives us a much better resolution, high resolution pictures of the entire universe, far, far out. It's the same thing with seismic. It gives us a much better, higher resolution picture of the belly of the earth which is where the reservoirs are.

What I'm showing you is one of the recent developments that the company pioneered, in fact there's a U.S. patent pending on it and several publications. If you compare the picture on the left with the picture on the right it's clear that the features, particularly the subsurface channels associated with the characteristics of the reservoirs are much more detectable on the right relative to the picture on the left.

Now the other thing that again is coming into play is the impact that IT technologies, and particularly the chip, the intel revolution is having on the entire industry and specifically on Saudi Aramco. It had a profound effect on the industry. The effect has been particularly emphasized and amplified in areas where we had a much better understanding of what's going on.

We today operate 48 drilling rigs. These are big, big rigs. Each one of our rigs has the capability of real live communication with our scientists back in Dhahran. It's very similar to NASA's mission control rooms. The concept is very very similar. Just like NASA is manning its rovers on planet Mars very very successfully with the twins, Spirit and Opportunity, that's exactly what we do.

We have communication with the rigs, with the drilling bit which is drilling 10, 15, 20,000 feet underground hundreds and hundreds of miles away, and we have the ability to see things within a one foot resolution in real time, 24 hours a day. That gives us a significant capability.

The picture that I'm showing here, in cast it's not clear, is a horizontal well, this is from the gas program, which is drilled about 13,000 feet and the well itself is a horizontal well. It's 2,000 foot long. It's placed in a 30-foot segment.  It's been a very very successful well. I'm not showing this as Star Wars example. This is the norm. Every well that we drill has this type of capability and it is making a difference in our production capabilities.

I'll quickly show you some field examples so that you have a better appreciation of where we're coming from. Shaybah is our second youngest field. It's been on production now for five and a half years and it's a very good example to talk about. It started production July, 1, 1998 with a production of 500,000 barrels. It's still producing 500,000 barrels. It's exactly in line with peak production forecasts and it's no surprise. It's because of the very deliberate diagnostics work that preceded the planning.

We also estimate on the basis of all the modeling studies that we have done, consistent with the field performance data, a production plateau of about 50 years. That's five-zero. I would say with all confidence that's a very conservative estimate. We would be disappointed if we don't get a plateau period of 65 to 70 years.

If there is a demand by the global energy market for Saudi Aramco to increase its production we certainly have the capability of going to a higher depletion rate. Right now it's one percent. We can go to two percent, so we can increase the production from 500,000 to one million barrels per day. That's roughly the production of the whole state of Texas. We believe we can sustain it at least 25 years if not more.

A few interesting things. Shaybah was the first field in the history of the company that was exclusively developed by horizontal wells. That was in the late 1990s. At that time horizontal drilling had just become popular, particularly in Saudi Arabia. The extent of the technology was just drilling single horizontals. Imagine a pipe about this diameter extending about one kilometer. From here maybe to the White House. I don't know the exact space, but imagine a hole going that far. That would be our typical completion for producing Shaybah.

Today we have evolved and improved on those technologies with the next generation wells known as the maximum reservoir contact wells, and that's what I am showing here. Where you have multiple branches, it's not only a single hole. If you have a lot of branches coming out so you have a lot more contact with the reservoirs and you have much much better diagnostics as far as the subsurface.

What does all that mean? I know this is Star Wars, this is great stuff. But does it make a difference or it's just good party talk?

Well, I talk a lot about parties about this, it's true, because I've been involved with it. But it's a lot more than party talk. The bottom line is this. In 1996, and this is a very tough reservoir. We were producing 3,000 barrels per day. Today actually we're producing 12,000 barrels from these wells. We can produce 25,000, 30,000 barrels if we want to. We don't, because of very strict reservoir management guidelines.

More importantly, people would say so what? You're producing more, but does that really change your bottom line? You bet it does because the unit development costs on a per barrel basis between this well and this well is three times lower for the MRC
wells, and this is not a technology that's only applicable to Shaybah. We're applying it all over. And of course it has to be applied very very carefully.

All of a sudden if you look from the satellite, if we had the ability of taking pictures, this is the top view of the reservoirs. This is how wells would look. These are actual wells. These are not wells from the future that we're drilling. These wells are already on production with tested performances. You can see the rates for yourself --10,000, 12,000, 12,000, different fields. We've drilled them in Ghawar. Some of the ones that we drill in Ghawar we can produce 40,000, 50,000 barrels per day very comfortable. We choose not to because of our reservoir management guidelines.

The point I'm making here is that we're living in a completely different world because of the technological breakthroughs that are coming in.

Just compare with what we had only about 20 years ago. In 1980s look from the sky by satellite. This is how a well would look, a vertical well, just going down. In the 1990s it's a horizontal well, one kilometer. Now compare that, it's the same scale, with the complexity of the structures and the different geometries.

Now superimpose on it all the new technologies especially the intelligent well technologies that are coming in which are giving us the ability to control the production in the subsurface. Then you appreciate why we're so confident about the future.

Now let's talk about Ghawar. It's so topical in the industry. Everybody talks about Ghawar. It's the super giant. The title is the biggest misnomer in the history of the industry. Calling Ghawar a field because Ghawar is actually a combination of so many super-giant fields. Some of them are shown. It's Fazran, Ain Dar, Shedgum, North Ulthamiyah, South Ulthamiyah, Hawiyah, Haradh. It's a huge giant.

A few statistics. Obviously it's the largest in the world. It was discovered '48. It's been on-stream since 1951 -- more than half a century. And a very comprehensive water injection program was started.

The size itself, it's about 174 miles by 16 miles. Just to give you an idea, that's farther than from here to Philadelphia.

We talk about Ghawar, what's going on with water cuts and pressures and maintenance problems. Well let us look at it. Let's see what's going on.

I'm going to point to the oil production here. In case you don't see it, particularly people in the back, it's from 1951 to year-end 2003. This is for Ain Dar/ Shedgum, which is the most mature part of Ghawar. I'm going to show you the reserve statistics on that.

First, look at the oil production shown by the green line. As you can see it goes through a trough here and this is because of low demand period. Then it goes up. Currently it's producing very very comfortably at two million barrels per day. Again, as a matter of reference it's twice the production of the state of Texas.

Now let us look at the pressure. If you notice the reservoir pressures are steady. Again, it's not an accident. It didn't happen just by chance. It's the deliberate product of very strict reservoir management policies and strategies. Pressures are monitored and managed very very carefully.

Let us look at the water. What's happening with water? What's happening with water is that water production is extremely stable over the last five years. The total water cut is 36 percent. For those who don't know what water cut means, it's percentage of the total fluid that comes through the surface which is water. Water comes with oil. The more water you product the heavier it becomes and it becomes relatively more expensive.

But again, to put you in perspective at this state of maturity that I'm going to show, producing 36 percent water cut is phenomenal by industry standards. Most of the IOCs produce at much much higher water cuts. 70 percent, 80 percent, 90 percent. Russia, we were talking about Russia, produces over 80 percent water cut. So here is Ain Dar/ Shedgum producing at 36 percent water cut after 50 years.

What does it mean as far as resource depletion? Let us look at the numbers closely. We have right now as of year-end 2003, the tank itself is about 68 billion barrels. The proved reserves is 41 billion barrels, which is 60 percent of the oil in place. And we are here. We are at this point.

Now if we go back in history about 20 years ago, our estimates were that we were only going to produce 40 percent from Ain Dar/ Shedgum. Our reserves were this much. So if we go by what we knew or what we chose to carry as reserves because of our very conservative approaches, we said this is the total reserves here. So when you come to this point the field is shut in and your production is zero.

Well, compare that with the reality. The reality is you're producing two million barrels and probably going to be producing two million barrels for a few more decades at very modest water cuts. So obviously your reserves are much much higher than 40 percent. That's the explanation for the type of reserves we're carrying which again are very conservative on the basis of actual field performance.

Now where are we heading with it? We feel very comfortable that we will be in excess of 75 percent recovery. So we're looking at another 10 billion barrels very very comfortably, and probably a portion of the contingent resources because of the future technologies and EOR capabilities that are coming on.

Now let's look at Ghawar total. Are we only showing you one part, Ain Dar/ Shedgum? No, let us look at the whole thing. Ghawar as a whole the last ten years. What do we see?

What we see is very comfortably five million barrels being on production and the few dips that you see it's because of low demand. Again, what do we see with the water cut? It was rising very gently, very very gentle by industry standards, and since 1999 actually has taken a dip. The reason is because of the new technologies, innovations, reservoir management practices we have actually reversed the trend and we feel very comfortable for the next ten years we will be able to continue that trend.

I'm not saying this only for Ghawar. We say this with confidence for the whole company. In fact for the year we just ended, 2003, for the fourth year in a row the company reduced its water cut levels. I don't know of any other company in the industry that has done that. The total company aggregate water cut for Saudi Aramco was less than 27 percent for year 2003. It's the fourth year in a row.

Okay, let's take a peek now at the future because I showed you mostly about the past. Haradh is the southern-most portion of Ghawar. Supposedly it has the toughest qualities so it's a very good case example to look at what we expect from Haradh. This is roughly equivalent in reserves to Prudhoe Bay.

What I'm showing you is an aerial map and you may be curious about the shapes of these structures. What they are, they're the new generation wells that we know, we refer to as MRCs, maximum reservoir contact wells with quadlaterals. Each well comes with four laterals. So it's a completely different next generation design, and it's more than that. It also comes with intelligent wells. So each one of the branches that you are looking at here has remote control from the surface, from our offices where we can activate, open things and close things. So in a way we have full control on what the well is going to do without any intervention at all. And I'm not talking about the future vision. We already have these wells.

Now what does all that mean? What it means is this field is going to come on in mid July 2006 with a production rate of 300,000 barrels per day. What is the plateau we're expecting? Thirty years. We would be disappointed with 30 years. We definitely will shoot for a lot more than 30 years. What type of depletion rates we're talking about? 1.7 percent.

When you forecast over to the future which is 2036, I may not be around. Most of you will be probably. At 30 years the plateau, we're still producing at 30,000. What is the type of water cut we're looking at in year 2036? It's about 22 percent water cut. Why am I so confident? I'm so confident because we've already done so. This is not something new. We've already done it in Abqaiq. We're doing all across the fields. We have our track record. We understand our reservoirs, we have our models. Now the oncoming power of the new generation wells, especially the intelligent wells, the intel revolution has reached the subsurface.

I know this is what everybody has been waiting for so I would like to now look at instead of the next 30 years, let us look at the next 50 years. Let us look at the next 50 years for Saudi Aramco. What I would like to highlight right now is that this is not a plan by any means. We would like to share some scenarios with you, some possibilities, what if. What if there is truly a demand? What would happen?

The first one is the current company plan which is to maintain its capacity at 10 million barrels a day. What we see is that we can comfortably meet a 50 year plateau very very comfortably, and all we would need on top of the 260 billion barrels of proved reserves we have is 15 billion barrels additional which corresponds roughly to 15 percent of probable and possible reserves.

As a footnote, the current company business plan for year 2005-2009 is precisely that, is reserves replacement of 15 billion barrels. We never fail our business plan. So if we just go with our business plan, 2054, here we come.

Now let us elevate the bar. Where do we go with it?

We thought just as a matter of evaluation, 12 million would be a good number. Here is 12 million. Again, it's just a scenario. If we ramp up by year 2014 to a production of 12 million, again, we believe we can sustain it very comfortably for 50 years and beyond.

We believe anything beyond 2054 is really going into the open speculative stage, so we thought even for what if game scenarios 50 years would be sufficient.

We looked at the reserves replacement requirements and again what we see is very very achievable. It's only 35 billion barrels which is 34 percent of probably and possible reserves. And please remember, this doesn't include any of the 150 billion barrels that I was mentioning.

Now we also look at the 12 million case, again, and again what we found out, you can do it basically after a similar ramp-up period, you can go up to 15 million and maintain it up to 2054. The only qualifier there would be that you would need 70 billion barrels of reserves replacement which again we feel is very very achievable.

Of course all of these scenarios, whether they're going to become the business plan or not it all depends on the world market conditions. It has to be commensurate with the global energy situation.

Again the question that comes, just like Mr. Abdul-Baqi mentioned, what about costs?  Let's look at the past and then I will comment on the future.

When we look at our production costs vis-à-vis our competitors, and this is from the BPs report. We see that we have a significant cost advantage. What we're comparing here, so that we're all on the same page, we're looking at the direct production costs, so this is the direct EMP costs of the company which in our opinion is the right metric to compare against the other competitors. That's roughly 70 cents versus the four to five dollar range that we're seeing.

Even if you say no, don't give me your EMP costs, give me your total costs, the costs still are under $2, $1.80. That wouldn't be the right comparison. We believe this is the right comparison, the 70 cents.

So this is where we are and we've been very very stable throughout. That's because a very deliberate portfolio management, reserves management, reservoir management policies and procedures. And we believe the future will be very very similar.

Of course we may eventually see some rises in costs. That's undeniable. But given the benefits that we're acquiring from the new technologies, particularly the intelligent wells and the new diagnostic capabilities and the very strong reliance on surveillance, we don't believe there would be an abrupt change and all of a sudden we're going to follow an exponential increase in costs at all.

The worst case scenario would be a very moderate increase in costs 10-15 years down the line.

Again, continuing with the same theme and I'm just about done with the presentation. What do we see with the future? Because what we see in the future is the reason, is the justification for our vision for the future.

Number one, what we see is real time reservoir management, just like I mentioned with respect to geosteering, geonavigation, and all the new capabilities that are coming on which is giving us the ability to follow our reservoirs with tremendous type of accuracy, remotely yet in real time. It's making a big difference. Intelligent wells. That has become the norm.

A hundred million cell models. It may not mean much to you because what is a cell? It's very much like the pixel in digital cameras. It relates to resolution. So the more cells you have the more resolution more accuracy. Typically, again, the standard in the industry is something like 300,000 cells today. Our standard is three to four million cell models. For Ghawar we have a ten million cell model. Actually for Ghawar we have dozens of million cell models. But yet we're looking at very soon the capability of having hundred million cell models. Best in Class practices. Again, very much consistent with the emphasis on reservoir management.

What does all that mean? The two things that we talked about over and over again. Lower unit development costs. Both development and operating costs. And definitely much higher recoveries.

When I say about 150 billion barrels, it's all because of these initiatives.

As a synopsis, these are the main thoughts that myself and Mr. Abdul-Baqi want to leave you with.

First and foremost I think it's important to realize that the company's reserves are very conservative and have significant upward potential. I mention a number, again very conservatively, is a future recoverable resource of about 150 billion barrels and most likely it's going to go up. That's over and above the current proved reserves, remaining reserves of 260 billion barrels.

Second, the company has the capacity and the commitment to continue as a reliable and cost effective global oil supplier. The capacity and commitment are the two key words and we feel very very comfortable that we will be a reliable supplier and we will be a cost effective supplier because of all the initiatives that I already mentioned.

Finally, the third one that we just discussed. Sustained production levels of 10, 12, and 15 million barrels per day well beyond 2054 are very achievable. We do not see a major challenge associated with them. Of course it would require the appropriate resource commitments, exploration efforts, EOR and technology applications. We believe all of those things are there.

With that, I conclude my presentation. Thank you very much.

[Applause]