殼牌 (SHEL) 2006 Q2 法說會逐字稿

Welcome to the second quarter Royal Dutch Shell results conference call on Thursday, July 27, 2006.

[OPERATOR INSTRUCTIONS]

I will now hand the conference over to Mr. Jeroen van der Veer, Chief Executive of Royal Dutch Shell.

Please go ahead, sir.

Thank you, operator.

First, let me welcome you all to our conference call.

I'm joined by our CFO, Peter Voser and also JJ Traynor from Investor Relations.

Please take a moment to read our disclaimer statement.

Today we will update from the performance of the company.

Now our strategic process.

All right, three key points.

First, the second quarter the financial performance is underpinned by overall good operational performance with CCS earnings up 36% to 6.3 billion and 4.6 billion mostly returned to shareholders in the form of dividends and buybacks.

Second, we are making good process with our projects under construction.

And third, we have launched two new major projects in Chemicals and Unconventionals.

I turn now to the slide which has in the middle competitive returns.

We are delivering on our strategy of more upstream and possible downstream.

Our major objective is to generate competitive returns and we think that growth of organic investment will create the best returns for our shareholders.

We are using our strong cash generation to invest in robust projects for the future of our company and to return cash to our shareholders.

I turn now to the slide which is adding new positions.

Upstream, we plan to open up some more-- sorry, upstream we plan to open up some 20 billion barrels of resources by the end of the decade.

Our investments are on track with good progress at our major projects.

Let me highlight two major engineering achievements so far in this year.

And secondly we successfully installed the Lunskoye-A topside last month.

If you think about the scale of that operation the topside weighs 22,000 tons.

This is a huge achievement and an important milestone for the project.

On the past conference, this morning I said 22,000 tons is lifting in one go the same as 20,000 cars.

Secondly, LNG is on track for a 2008 startup.

The Gulf of Mexico we have restarted the Mars platform, which was so badly damaged in the 2005 hurricane season.

This was not a simple repair story.

But Mars today is producing some 170,000 barrels per day oil equivalent.

That is 10% higher than before the hurricane we used during the repairs made some changes as well.

We have also made good progress on portfolio development both upstream and downstream and have many new opportunities for the next decade.

You can these new positions on this map.

Let me talk about a few of them.

In Canada group companies have two major oil sands operations those involving mining such as the Athabasca Oil Sands project and in situ operations where oil is produced through wells using heavy oil technologies.

Shell Canada's purchase of BlackRock combined with our earlier acreage acquisition of SURE Northern Energy has added 48 billion barrels of oil in place with our in situ portfolio at a cost of some 2.6 billion.

We now have around 55 billion barrels of oil in place in our in situ acreage in Canada, a very strong platform for the future.

The slide which starts with downstream.

In the downstream, I am very pleased to confirm that we have taken the final investment decision on new chemicals cracker in Singapore.

This has aligned us to two key downstream strategies, to invest in growing Asian markets and to further integrate refining and chemicals manufacturing.

Singapore is an important hub for Shell.

Our Bukom refinery is our largest worldwide and we have petrochemical [chemistry] capacity over there already.

We will be adding to the chemicals capability with an ethylene cracker integrated with the refinery.

In the United States, we are closely at an opportunity to expand both [inaudible] refining capacity in Texas with an expansion of up to 325,000 barrels a day at Port Arthur where we have a joint venture with Saudi [Rampco].

This could create one of the largest refineries in the US with capacity of up to 600,000 barrels a day.

Construction could begin in 2007, which is subject to regulatory approvals and the final investment decisions.

Next slide about growth potential in unconventionals.

Let me spend a few minutes talking about our strategy in unconventionals.

First, what are unconventionals?

This is a pretty broad term but to put it simply this is an area where you need to use [de novo] technologies to produce hydrocarbons.

Today, that means oil sands and gas-to-liquids.

In the future, we have perhaps [novel] technologies like coal-to-liquids and in situ conversion of oil [shale].

We currently produce less than 5% of our worldwide output from unconventionals.

We expect that percentage to grow although I do expect to see a portfolio dominated by conventionals rather than unconventionals.

In the '97 piece, Shell was one of the leaders of what was then a new technology to liquefy gas to deliver it over long distances to Asian customers.

Since then, that unconventional niche cash business has grown into a conventional global and rapidly expanding LNG industry, where Shell has a leading position.

We hope that our GTL technology-- gas-to-liquids technology-- can be as strong a story in the future as LNG is today.

Unconventionals activities carry high upfront costs and often require heavy investment in the downstream as well as upstream facilities.

However, the integrated developed cost per barrel of resources can be similar to conventional upstream projects.

Unconventionals can be as profitable as conventional, especially when oil prices are high.

They play an important part of our strategy to increase our exposure to price upside.

I go now to the next slide which shows two photographs.

I'm very pleased to confirm that we have taken the final investment decision on the Pearl gas-to-liquids project in Qatar.

This is the first world-scale integrated complex of its kind and is an important project for Shell.

Shell Canada continues to study the first phase of the expansion of the Athabasca project, which could open up 1 billion barrel of resources and around 100,000 barrels per day of production on 100% basis.

Shell Canada should make their decision on this project shortly.

I change to the next slide labeled Pearl GTL.

Unconventionals are totally integrated projects from the resources in the ground to the retail customers, allowing us to add value all along the chain.

For example, the Pearl GTL project will develop offshore natural gas from Qatar's North Field and convert it into clean liquid fuels and base oils at the world's largest integrated GTL complex in Ras Laffan Industrial City.

The Pearl GTL complex will consist of two 70,000 barrels a day GTL trains and associate facilities.

And the project will also deliver approximately 120,000 barrels of oil equivalent a day of [inaudible] in liquefied petroleum gas and ethane.

GTL Fuel, the largest component of the product slate, can reduce vehicle emissions when used as a fuel component for existing diesel engines, helping to meet increasingly stringent emissions and standards around the world.

Pearl will develop around 3 billion oil equivalent of resources.

We have previously talked about typical development costs of $4 to $8 a barrel oil equivalent of resources for major projects, excluding downstream facilities such as LNG liquefaction plants, GTL plants -- sorry, and oil sands [upgraders].

For a GTL plant like Pearl, where the main outputs are refined products and lubricants, it is important to understand that the project cost covers both the traditional upstream costs and also the equivalent expenditure for refining facilities.

For Pearl, we are expecting the integrated project cost to fall within the lower half of the 4 to 8 barrel per oil equivalent resource rates so it falls between $4 and $6 per barrel.

This is quite clearly an attractive cost profile compared to conventional projects.

We are investing in unconventional projects with very long lives, typically more than 20 years before production starts to decline.

Like our LNG business today these unconventionals will become an important element of our production in the next decade.

I hand now over to Peter Voser.

Yes thanks, Jeroen.

Good afternoon and good morning everybody.

I start with Q2 results highlights.

I'm pleased with our earnings performance in Q2 '06.

Net income on a CCS basis was 6.3 billion which was an increase of 36% compared to the same quarter last year.

This included provisions for litigation, revisions to Canadian taxes and mark-to-market effect from our UK gas positions.

Also in the downstream we have free structured employee retirement plans in France from a defined benefit plan to a defined contribution plan.

Under IFRS this means recognizing a charge of some $130 million in this period rather than in future periods.

So excluding these items our CCS net income was $6.5 billion.

Cash flow excluding working capital and taxation effects was also strong, up 37% compared to last year.

Our dividend for Q2 '06 has been announced at euro 25 cents per share, an increase of 9% year on year.

I'll move on to oil prices and margins.

Oil prices, US refining margin and US cracker margins were all higher in Q2 '06 than a year ago.

Retail margins were weaker.

Global political tension had a major impact on oil prices partly tempered by comparatively convertible US inventory levels.

Refining margins were supported by tight supply due to robust global demand and refinery shut downs in the US, Asia and Europe.

The third quarter so far has seen strong energy prices.

I move on to earnings momentum.

Looking at the drivers of our earnings performance the business segments did better than a year ago.

That is unusual -- an unusual situation in an integrated company but for now at least these are good trends to see.

Upstream, Brent oil prices increased by some $18 although natural gas prices were slightly down.

Exploration and Production earnings were 46% higher than a year ago mainly reflecting strong oil and gas realization, some taxation credits and a shift to higher margins production partially offset by lower volumes and higher costs.

This compares favorably with the increasing market prices of Brent, 35% and WTI 33%.

GP earnings increased substantially versus year ago levels.

On the downstream our oil product earnings increased substantially from Q1 2006 levels.

This was driven by a strong recovery in refining margins in all regions although marketing margins were under pressure in the same quarter.

Utilization rates in our refinery declined because of an extension of planned down time in Europe.

In the US, however, they were better than in the hurricane quarters last year.

Sales volumes were impacted by asset sales and the options to supply in our B2B businesses.

Demand remains robust.

Chemicals earnings also recovered from Q1 '06 levels with satisfactory margins despite rising feedstock prices.

Our new petrochemical facilities at [Shuanghuan] in China reached 90% operating rates at the end of the quarter.

Moving onto production.

Oil and gas volumes were 3.25 million BOEs a day in Q2 2006.

This includes its new production from the Bonga and Erha in deepwater Nigeria and Salym in Russia.

By end of the quarter, our production in deepwater Nigeria had built to around 150,000 BOEs a day Shell share.

Our LNG sales volumes increased by 15% to 2.8 million tons with the ramp up of Nigeria Trains 4 and 5 and in Oman as well.

This trend is in line with our LNG gross targets.

Higher oil prices meant that we received around 20,000 fewer BOEs a day from our production sharing contracts than in Q2 2005.

There was also unplanned down time related to the security situation in Nigeria and hurricanes in the Gulf of Mexico.

Excluding these impacts, our production was flat versus a year ago.

At the present in Nigeria, Shell and the government are beginning to engage with the communities in the effected areas and no firm date can be given for the resumption of production.

An average of some 177,000 BOEs per day production was shut-in across Q2 '06 with no material financial impact.

This is not a static situation.

It's simply a set of well shut-in.

It is known that some facilities have been damaged and the extent and time to repair are uncertain.

We are not going to predict when these wells will restart.

Safety is clearly our first priority.

Given these uncertainties in Nigeria we expect production around 3.4 million BOEs a day for 2006.

But I want to stress that is not a prediction as to when production there will restart.

We continue to work closely with the authorities to achieve early as possible access and restart of production, but we are not going to predict when this will be possible.

As I've said safety is very much our first priority.

Moving onto cash flows and unit earnings, our unit earnings performance in the quarter was robust compared to industry margins.

Excluding identified items, balance sheet margins were $3.60 per barrel, an 8% increase versus year ago levels.

Upstream unit earnings were $14.20 per barrel or oil equivalent in Q2 2006, an increase of 46% versus year ago levels.

Our unit cash margin both upstream and downstream are growing and seem to be competitive within our sector.

Competitive cash generation is very important to us given our future capital requirements so we are tracking these trends very closely.

Let's move onto returns, return on capital employed continues to be an important measure for Shell and we are competitive against our peers.

That raw change in Q2 '06 was 26% compared to 24% a year ago.

You can also see that our rubbage capital employed of around $150 billion is among the highest in our peer group.

We expect it to grow steadily in coming years.

Let's see what we do with the cash.

We continue with our balanced approach to the uses of our cash flow.

We are servicing our debt and dividend commitments and have a major investment program on the way.

Base spending this year is expected to be around $19 billion.

So far we have invested around another $2.9 billion on incremental opportunities.

In '07 we plan to spend some $20 billion in organic growth.

Shell is making large-scale infrastructure investments to open up our resource space.

And we are on track to open up some 20 billion BOEs of resources by the end of the decade.

So we are expecting our capital spending to stay at relatively high levels across the rest of this decade.

Like the rest of the industry, we faced clear cost pressures because of high capacity, utilization in the oil service businesses.

We are working to mitigate those pressures by looking closely at the timing and the scope of our projects.

I want to be clear here with you that we see a number of projects including partner operated projects where costs of current levels are a considerable challenge, which might impact our final investment decision.

Cash flows related to cash flow return to shareholders, which is the next slide.

Finally on payout we have increased our dividend by 9% from Q2 '05 to this quarter.

We have also continued to share buybacks with some $2.5 billion invested on share repurchase over the quarter.

We made extra dividend payments in '05 because of the change from semiannual and to quarterly dividends.

I'm sure you remember that.

So far in '06 we have been extremely competitive with 2005 payout levels.

So let me now hand back to Jeroen for the summing up.

Thanks, Peter.

To sum up, our operation performance is improving and our major projects are on schedule.

We have made a major step forward with our unconventional strategy, taking FID on the major Pearl gas to liquids forecast.

And conventionals will be a growing part of our portfolio and one element in our continued success.

Making substantial investments in new energy infrastructure is our business.

And will drive our profitability into the next decade.

The industry faces challenges from the increasing complexity of projects.

Our technology, our people, and our experience and also the diversity of our portfolio enable to meet those challenges.

We remain committed to delivering competitive incurs for our shareholders.

And of course we focus on delivery, delivery of our projects and delivery of competitive and safe operations.

So now over to your questions.

Operator?

Thank you, sir.

[OPERATOR INSTRUCTIONS]

Thanks.

The first question comes from Mr. Tim Whittaker.

Please state your company name followed by your question.

Yes, good afternoon.

It's Tim Whittaker from Lehman Brothers.

I've got a couple of questions around both Pearl and Athabasca.

There appear to have been some cost increases around Pearl and also around Athabasca.

And you quoted a dollop a barrel of reserves figure for Pearl.

But for both those projects, could you say now what you think the dollars per barrel of daily capacity is that you're spending?

Also what you think the breakeven oil price is on an MPV basis?

And finally on Athabasca could you say whether the potential higher Cap Ex will impact your longer-term Cap Ex budgets?

OK.

I guess I start with it.

What we, let me give you some numbers.

I just repeat what we said on Pearl.

We are thinking on a development cost and that's where for ops demand for down seen between $4 and $6.

And that's roughly we are looking at the results base of 3 billion barrels.

The upswing production piece of Pearl is roughly 320,000 barrels.

That's an additional information which we can get which you can work out from the total resources.

So I think that's as far as we go on areas.

On the Athabasca side we are looking at production we are today at 155,00 barrels a day name play capacity.

Shell commodities looking into a first expansion of roughly 100,000 barrels so that would add another 100,000 barrels of production on 100% basis.

On the pricing side we said that we are taking a full portfolio look at when we look at our investments.

It's clear we are driving our investment decisions according to cash.

And we are looking at various prices on the upside but also as many times already talked we also look at conservative prices to the downside.

I think on the unconventionals, which will make up, which make up today some 5% of production growing to 10 to 15 by the middle of the next decade.

We would look at normally from a cash point of view the way we look at our hurdles, we would look at prices which are have to be greater of $30 a barrel to meet our screening criteria.

From a Cap Ex point of view I said we are, if you take Pearl and if you take for a moment an assumption for the moment that Athabasca goes ahead.

First expansion we are looking at 4 billion barrels of resources out of the 20, which we have said we will actually unlock before the end of the decade.

We have given guidance for this year on the Cap Ex 19.

We have given guidance for next year some 21.

We are not going to give further.

It is more precise than what we would have already said.

That given our project pipeline, given the way we are developing our bios, given the way we have our production targets in the next decade, we look towards relatively higher Cap Ex spending in the years to come.

That maybe what you were used to at the end of last decade or early part of this decade.

Can I ask a slight different question as well?

You've disclosed your production decline; your field declines in the quarter.

It looks to me to be sort of roughly 5 to 6% on that chart.

Could you confirm that that number is after Cap Ex on your existing fields?

And also could you give a forecast what production decline will be in the remaining quarters of the year?

I'm not going to give you new guidance on a quarter-by-quarter basis.

We always said that on a portfolio basis across all portfolios we are looking at on an average between 6 and 8%.

That had some higher decline rates in certain areas like the Gulf and in the North Sea, by North Sea is actually in that guidance.

But the Gulf would be higher.

So on an average it's 6 to 8.

And I think that's as far as I can go.

And that's after maintenance Cap Ex on those fields, is it?

That's correct.

Thank you.

Thanks.

The next question comes from Mr. Mark Iannotti.

Please state your company name followed by your question.

Yes.

Mark from Merrill Lynch.

Sorry to go back to Pearl again, Peter.

But it's going to be one of the biggest projects in your portfolio.

Can you give us any guidance at all given the complexity of this project on how we can model this through earnings?

What kind of no pack contribution do you think this thing can make once it's fully commissioned, either today's prices or your reference prices or some sort of price?

But can you just give us some indication of what you think the earnings contribution from this asset could be?

And maybe also if you could give us an idea on the phasing of the timing of when you made both the barrels from the project?

Thanks.

Can you just repeat the last question?

Yes.

Can you give us an idea of the booking schedule for the project into reserves?

OK, I start with the second one and go into the first one, which is more of an economic one.

From a reserves point, if you, we are still in discussions with the SEC.

This is kind of a new beast here and doesn't fit the guidelines in an exact way.

So we are in discussions.

And hence it's actually too early to give you any guidance on that as we haven't crossed the bridge that we can actually take it as proved reserves.

So I think we will bid you most probably some updates when we get into the reserves reporting season.

But the discussions with the SEC are still ongoing.

I think you expected that anyway.

And I will not give you more precise cash flow, et cetera figures.

But let me give you a few things, which should give you some confidence.

I already said that we need prices above $30.

So that gives you a certain insight.

I think you can easily assume that the cash flow per barrel is accretive as somewhere in the mid 30s.

And you can also take a lot of confidence out of the fact that we are taking 100% of this project because we are convinced that it will be very accretive in the longer term.

OK, thank you.

Thanks.

The next question comes from Mr. Daniel Barcelo.

Please state your company name followed by your question.

Hi, yes good morning.

This is Daniel Barcelo from Banc of America.

Comment as I could on the low natural gas environment and how that perhaps is changing some of Shell's thinking perhaps short term.

Basically is as you're doing anything differently in terms of your L&G tradings going forward?

Are you considering other options in terms of European gas contracting pricing?

Or specifically are you starting to change some of your thinking towards drilling in particular in the U.S. gas portfolio?

Thank you very much.

If you look at gas pricing, you have, we have always seen certain and general.

And then I go quickly to the L&G side of it and then to the States.

And then I check whether Peter would like, because this is quite a wide question.

So let's go in big steps and to see whether Peter likes to add to that.

The gas pricing is so far in Europe basically still coupled to a mixture, to a basket of oil prices, albeit there's a certain delay.

Over the past, even over the past years in the States it was probably not as the coupled as we expected 10 years ago.

Having said that, over the last quarter you've seen that you have in fact a rising oil price while there was some pressure on gas prices.

We have to take into account seasons as well.

Over time we expect basically 2 things but they mostly go relatively slow.

First of all is that you will see that all the time more spot trade for gas will develop.

That the large part of the gas is certainly the L&G part will be for the very important part be careful by long term coal tracks because that is the basis of purchase acquisition making.

Secondly, the decoupling of oil prices with or with delay is all subjected to the industry.

And I think that slowly, slowly you may see new forms of contracts.

Now that is the general gas scene.

We are at both sides.

What I mean there we have of course the experience for long term contracts in many countries and for many resources.

Better so, we have a lot of gas trading.

I think that's in our special division we have coral, mainly based in the States.

But we are also active traders with L&G around the world for both cargoes.

Last but not least of course in the whole trading, also in the whole drilling for gas in the U.S. you may, you can afford quite high drilling costs if you can bring it relatively quick to the market.

Again, long-term gas prices may have a different development.

And then we work, as we do at the oil site, and we work with a grid of oil prices to screen and we have grid of gas prices as well.

Let me look at Peter what he would like to add.

Well it was an excellent answer.

Let me maybe just add one, which we already touched upon in the first quarter.

Quite clearly through our global leadership on the L&G side and through our marketing and trading capabilities we are obviously optimizing on a worldwide basis our capacities in L&G.

And we are taking obviously our good market position into account when we look at Asia, Europe, and the United States.

And there is a real demand for L&G at the moment.

And through ship diversion and cargo diversion, et cetera, we are using our capabilities in order to actually achieve higher prices and hence actually increase our earnings as well.

So this is more a general comment.

But that underlying apart from our 15% L&G growth rate, which we have, is underlying actually our good and very good gas and power results.

Operator?

Thanks.

The next question comes from Mr. Jon Rigby.

Please state your company name followed by your question.

Yes, hi.

It's Jon Rigby from UBS.

Can we just go back again to Pearl, you quote a range of prices on your development costs for resource between 4 and 6.

Can you just talk to what the assumptions are behind that?

What the sensitivities are?

Because of course when you gross it up it's a vast range in absolute price.

So can you just talk to what the assumptions you may behind it and where it may flex between the bottom end and top end of that range please?

No, I think we give you the range because that's the range, which we are working on.

I think I can give you one or two other information here.

We are in the process after the FID now to actually allocate contracts to third parties, which are going to be in the order of some $10 billion.

The second one is we are looking at the building time of some 4 years before it comes on stream.

So you need to cover some uncertainties.

We have learned from other projects, which you have fully brought into obviously the preparation of Pearl from sacking from non-high from the L&G experience.

In the way we want to actually structure the whole implementation and construction of the project and how we actually take costs into account.

How we allocate contracts, how much contingencies we build in, et cetera.

I would just like to mention I'm very pleased with the project from a different angle.

When I compare to what certain companies actually pay in the market for getting resources in the ground.

If you then compare that to the development costs actually in Pearl, which is $4 to $6 where you don't need expiration spend on top of it.

I think this looks very attractive.

And that's why we are doing it.

Then for the 4 years I see a mid 2010 start up then.

We said somewhere there around, yes, 2010.

And then just to come back to the point, where within that 4 to 6 was the current condition steel costs, price of contractors, where would that fit you within that range do you think?

Jon I think you know that we have taken the last 12 months to prepare this thing in terms of contractors contract that we have been tendering.

And I think that's as far as I go.

We have splitted the project into the various parts.

We have had very good and excellent contact with the Qatari.

They have shown a great vision, actually, to develop this project.

Looking out further let's say channels for the Qatari does in the long term.

We have a quality sea contract, which encourages both sides to actually optimize the profit.

And I think that's where you're going.

It is for us not that important to be very specific and detailed on the kind of questions you are asking.

I think we took the necessary time to develop this and get to FID.

And we are there now.

And both sides are happy with what we are signing up on.

Thanks.

Thanks.

The next question comes from Mr. Mark Gillman.

Please state your company name followed by your question.

The Benchmark Company.

Good afternoon, gentlemen.

I had a couple of questions.

First related to Pearl, Peter did I hear you say that you were taking a 100% working interest?

And is the contract still an integrated PFC all the way through the refinery level?

Second question relates to Pernis.

This refinery's reliability history recently I think to say the least has been poor.

And I'm wondering what kind of measures you're considering taking in order to improve this from the long term?

Third and finally, Peter you indicated that several projects might be vulnerable as a result of inflation and industry costs.

And I wonder if you could be specific outside of Athabasca as to which ones those might be.

OK.

I think I'll take one and three.

And as the next refinery manager is sitting next to me, my Chief Executive I hand that to you.

On the first question I think the answer is twice yes.

Just to repeat it we have 100% working interest and it's a fully integrated BSE in that sense.

The third one this is obviously a constant process when we do ranking of projects, when we look at the approval of projects.

I think we have said earlier on and I use most of that example again, we are looking at in the Gulf of Mexico in more south for example to some delay.

We are looking in some other areas.

But they are not at this stage already communicated.

So, I think what I can tell you is that we are running, at the moment, we are working at 70-90 of larger projects and they're all under scrutiny in that sense.

And we will take one or the other division there.

The one which you have quoted is the Gulf of Mexico.

For [inaudible], over to you.

Thanks for the question, Mark.

It's, of course, actually refinery manage of Pernis, refining, by the way, albeit some time ago, but there's still a question close to my heart.

And let me start to say, we have, in my view, in the second quarter, really good earnings in the downswing, in oil products.

But they would have even been better if this very large and complex refinery of Pernis would have shown better reliability.

And what the management has decided in Pernis, because we have the [load], we have the special – how do you call it – [inaudible] cause analysis and a kind of order to provide the root causes of it.

And to keep a long story short, we feel that there has to come certain changes to the organization.

We leave that to us and we have to work that, of course, with the staff of the works council over there.

But secondly, in close cooperation with the authorities, we have to find a whole program to increase the reliabilities.

And that will cost some money, some capital money.

We have to think about a few tenths of millions of euros and that is looked by, let's say, as well from the authority as our own experts.

And we think that, in combination with behavioral changes, we are convinced that we got this very important refinery back on track.

Thank you, guys.

Thanks.

The next question comes from Mr. Neil Perry.

Please state your company name, followed by your question.

Hi.

It's Neil Perry from Morgan Stanley.

Two questions.

One is you talked a lot about this.

The acreage and resources that you've taken on in Canada.

And you've taken it on at relatively limited cost versus the resources.

Can you talk a little bit about whether you think you have got some sort of new technological advantage that you can apply to that to leverage that position.

And if so, is that in the production part or the processing part?

And then, secondly, can you talk a bit about the expansion at Port Arthur and what sort of working numbers you're using for the cost per flow in barrel of that extension or what sort of long-term refining margin you're assuming in the U.S. that might encourage you to make that investment decision?

We try to go in big steps.

This – in Black Rock, I'm sure is about [40 to 80] billion barrels oil in place.

All of that will be recoverable.

Pay $2.6 billion.

That's a bit more than $0.05 paid for oil in place.

Now, with the present oil cents technology in today's mining and the steam-assisted stuff in [C2], you have a certain percentage of recovery.

And of course, we have in both experience, endorsed technologies.

We are busy with research where we can increase that percentage on a significant basis.

Now, we have, of course, first do those reserves projects and to prove that technology.

But that could help us to get a lot more out of oil cents and we expect that if the technology is successful, you can apply it to Oil Shell as well.

So, that's why we are so keen to have more acreage over there.

Now, your question about Port Arthur refinery, we have [inaudible] three of the 25,000 barrels per day.

That is, of course, the combination of distilling capacity and operating capacity.

It's too early to say we are not close to [FIV].

Both the cost per barrel could be and that's exactly why we do those studies.

OK.

Can I just come back on the oil sands?

What sort of increase in recovery factor are you attempting to go for?

If I would answer that, I would be convinced that all my competitors would follow that answer with great interest.

I'm sure they would.

OK.

Thank you.

Thank you.

The next question comes from Mr. [Burt Auchenheizer] from [Defries].

Two questions, if I may.

First, gas prices in Asia are still relatively low.

Do you foresee them already rising in the next season or is the extent of your contract such that these take a little bit more time?

And secondly, going back on Pearl, but not only Pearl.

Also on the [CTL] project, what sort of returns, what sort of [unavailable] do you typically foresee in that kind of, if you call it, midstream project, whether it be in upper tens or what sort of range do you currently [envision]?

Gas prices in the Far East are heightening.

And the reason for that, there's a lot of pull on the LNG now from the United States.

So, we see, relatively, on the West Coast, where we are building, where we have terminal capacity, if we have [Baja], California, for instance, with our terminals in under development, which can receive LNG from the Far East.

On the second question, I pass all the Pearl questions to Peter.

Yes, thanks, Burt.

Maybe first start with a very general remark, which is we are not going to give project specifics – cost estimates, but also not very specific return activity.

But we are working on portfolios and we are working on various businesses and that's the way we are going to run it.

Let me just add maybe one or two things which I haven't already said on Pearl, which is important when you look at these things.

This is a typical project where you invest and integrate it upstream and downstream.

And you have the heavy investment up front and you have then actually quite a long-life project where, let's say, you have [inaudible] risks.

You have future CapEx spending because you have actually spent that up front and you are then just in the producing mode with hardly any decline rate or no decline rate to deal with, et cetera.

And I think that actually gives you a good insight with the other way is components I've given you on how you can actually look at cash flow, how you actually can look on return achievements over time.

Typically, these long-life projects, being it here or being it in [inaudible], there typically are 20, 30 years of constant production at relatively the same level.

And that's exactly what I was strategy striving at.

Thank you very much.

Thanks.

The next question comes from Mr. [Gordon Gray].

Please state your company name followed by your question.

Hello?

Hello?

Hi, sorry.

I wonder if you could just update us with progress on two things.

One is the progress for the first half of the year in your exploration strategy.

And secondly, any further timing stroke cost estimates on Gorgon?

The explanation – we pour it once a year.

So, which we have [inaudible] is last year.

We hope to drill 15-bit caps in addition to our normal laser program, as small exploration.

We report on that, so coming January, [as of Jan], we have, but we can say so far so good.

Cost estimates for Gorgon in for Chevron, the operator to report.

That had started in the industry.

The operator reports whatever they have to report on behalf of [inaudible].

OK.

Thanks.

Next question, operator.

Thanks.

The next question comes from Mr. Jason Kenney.

Please state you company name followed by your question.

Hi.

It's Jason from ING.

A slight follow-up on Neil's earlier question on Canada.

When do you expect commercial heavy oil volume contributions from Black Rock in Canada?

And secondly, on the – you mentioned the percent increase in recovery.

Would that be focused on the extraction process or on the upgrading process?

And then, secondly, could you give us a steer on [Aman] L&G, please and the volume contribution this year and the ramp up to 2010?

OK.

L&G will – Peter will look at that.

Black Rock is an investment by Shell Canada.

And they are a minority share, so they have to report on that.

But of course, Black Rock will be an integrated part of Shell Canada.

Shell Canada thinking how they, over time, like to develop their aspiration, going from on a 100% basis, 155,000 barrels per day oil sands production, to 500,000 barrels per day.

Your second question, the percentage of recovery, why do we think that we can get it higher?

That is by new – by applying new technologies in the ground.

That is the essential story of there.

And LNG question, I turn to Peter.

Yes, most difficult to understand, but I think you were asking about Aman.

Is that correct?

Yes.

As you know, we have gone [life] there with [call out three].

It was an LNG project which was built at the lowest unit cost ratio.

Has a record startup in, if I'm not mistaken, I think it was nine days.

So, it's – the startup was excellent, the ramp-up was excellent.

So, we are very – we are very positive on all the news we are getting out of Aman.

So, we are pleased with the progress and we are just going further with the '03, trying to optimize them.

That's as far as I can go in terms of predicting the next few years.

So, fully operational today already.

Yes.

Yes.

Great.

Next question, operator.

Thanks.

The next question comes from Mr. Robert Kessler.

Please state your company name followed by your question.

Yes.

It's Simmons & Company.

Good afternoon.

A couple of callers have already tried to get an answer on this and appear to have come away empty-handed.

So, I'll try again.

You focused several times today on low unit capital costs of unconventional resources.

At the same time, it seems to me, internal rate of return is more appropriate for shareholders.

And I recognize you don't want to speak to an individual project or another, but in the global context, looking at your conventional versus unconventional portfolio, can you rank the relative internal rates of return?

Let me first answer you in such a way that cash and returns are absolutely crucial when looking at projects.

So, these are key criteria for us, which all projects are, obviously, screened on.

Your question, obviously, has one big assumption in it and that's the oil and the gas price.

So, at what levels you are looking for?

We have said in the strategy presentation that we are positioning the company for higher oil prices.

And we are positioning it also for higher upside.

And that's why, clearly, where unconventionals has quite a key role to play.

So, from that point of view, I think, that's the way we look at these things and we see them quite clearly as competitive at higher oil prices to the more conventional areas which you are running today.

And I think you understand.

You have given it a good shot again, but I think I will not obviously use numbers.

But I think, I said before, I'm prepared to say it – it's higher oil prices.

That's what we are strategically aiming at where competitive is conventional.

Can you just, real quickly, on current oil prices, then being above most people's historical expectations, on current oil prices, do unconventionals generate a higher rate of return in your portfolio?

I'm not going to give that to you because, I mean, then it's just another way of getting through the back door to get the same answer.

So, I think we are developing, we have our strategy and we are moving.

We have 5% of unconventionals today in terms of production and we aiming at 10, 15 in the middle of the next decade.

And I think I have to leave it at that.

OK.

Thank you.

Thanks.

The next question comes from Ms. Nikki Decker.

Please state your company name followed by your question.

Good afternoon.

Nikki Decker at Bear Stearns.

Peter, maybe you could comment on your previous guidance on production for 2007.

I have you down for 3.5 to 3.8 million BOE a day.

And also, at $50 oil, what is your sensitivity production affiliated with PSCs to a $1.00 change in a barrel of oil?

OK.

On the production side, it's correct what you quote – the 3.5 to 3.8 – and that stays.

And I think on the – if I understand your correction correctly, then per dollar, we are in the 2,000 to 4,000 barrels per dollar on the PSC side.

To the first one, may just to add, this obviously assumes that we have a restart in Nigeria somewhere in '06 to get to the 3.5 to 3.8.

OK.

Thank you.

And how is – how is the performance at Bonga, relative to your expectations so far?

Can you just give some color on what's going on there?

Yes, certainly, I can on that one.

We are very pleased with the ramp-up in Bonga.

It started very well off.

We kept after our [inaudible].

The out of Bonga there are actually Shell share.

We are at 150,000 barrels.

That's above expectations. [inaudible] has actually offset some of the product – lower production, due to the securities which we had in Nigeria.

So, we are very pleased with the operational performance there.

The team has done a great job in starting that one up.

OK.

Great.

Just one more, if I could.

On your share buybacks, first of all, you've indicated that you've purchased $4 billion worth in the year to date.

I assume that includes purchases in the quarter to date.

No, the full period is actually up to the end of June as we are communicating to the market day by day.

We have now, as per yesterday, we were – if you add that together, we were at $4.9 billion.

So, we are let's say we're around which we are at $5 billion more or less now.

So, you're on pace for something well above what you've initially indicated.

Can you give us some new guidance on where you might come in at the end of the year?

Yes, I think I repeat my guidance.

That will be about five billion.

But I will not give you an exact one.

What we are doing is we are driving dividends.

We are driving the organic growth.

And then, if we have got spare capacity, we allocate to share buybacks, but also to further organic or even other opportunities growth like we have done this year by actually for $2.9 billion with the Black Rock acquisition, the Canadian [inaudible] have bidded an acquisition in Brazil.

So we have optimizing both sides and we are determined to optimize the shareholder return.

This is one of our key strategic streams and we will optimize it in that way.

And we will just deliver what we can deliver and keep the balance between short-term shareholder return and low-term shareholder return.

Thank you.

Thanks.

The next question comes from Ms. [Irene Himona].

Please state your company name followed by your question.

Good afternoon.

It's [Irene Himona] with [Exxon B&B Paraba].

Two quick questions, if I may.

First of all, given the price environment, would you contemplate accelerating disposals from the existing portfolio?

And secondly, a look at your first half cash flow statement.

CapEx of 10.4 billion is up about 56%.

But depreciation appears to be down about five percentage points.

I'm just wondering how we can reconcile these.

Thank you.

OK.

I think the first one – we have a general strategic theme around portfolio management.

We have said between $2 to $3 billion on a through the cycle basis we will divest as part of our portfolio management.

I will not give further guidance on that what we are looking at, at the moment.

On the CapEx side, yes, it is up, but most of you are including there – I'm just guessing – the three – $2.9 billion which we actually spent on acquisitions.

So, I think you have to take that out and then take the ratio.

We are still up compared to last year and that would expect when you move from $15 to $19 billion.

So, from that point of view, you take that.

Now, the depreciation, obviously, there is an element which has to do with how your reserves move, how your production actually moves, et cetera.

So, I think that is as far as I can go now.

I don't have further details with me.

But I think the 56% is always stated.

You have to take out the acquisitions.

Sure.

Thank you.

Thanks.

The next question comes from Mr. [Stefan Sucode].

Please state your company name followed by your question.

Good afternoon, gentlemen. [Stefan Sucode] from [Seki General].

Tax rate seems to have significantly gone down between Q1 and Q2.

And I was wondering whether you could perhaps explain where the difference comes from.

Yes, thanks for the question.

I think, let me first reiterate where we see the long-term tax rate going.

That's 41% to 43% and that has not changed.

So, what you have seen in the second quarter compared to the first quarter are really – is two effects.

The first one is a geographical and business mix.

So, between upstream and downstream and between various countries.

So, that's part of the normal business, part of the normal, let's say, makes us which we have.

And the one which is an unusual one in that sense was the tax rate change in Canada, which released some $200 million and the $200 million was mainly actually in the exploration area.

So, I think that was the unusual.

Otherwise, we are on track to end up in the 41%, 43%.

So, it was given all in place, actually, in that sense, a normal quarter apart from Canada.

Let me also remind anybody on the call that, in the third quarter if [inaudible] finally, which I think it will take place, we will have then a charge like the outline in our press release from roughly $300 million regarding the UK tax rate change, a charge in that sense, including deferred taxation.

And then, later on, on a [Q&Q], depending on the oil price, it will be between $100 and $150 million.

So that you know that in going forward.

That is included in our 41%, 43% guidance for longer term.

Thank you.

Thanks.

The next question comes from Mr. Fred Lucas.

Please state your company name followed by your question.

Fred Lucas, Cazenove.

You said a couple of times that you're positioning the company for higher oil prices.

I just wonder why, to be consistent with that, your not managing your balance sheet on the same basis.

Perhaps you could comment.

And the second question.

I just wonder if you've reiterated today the statement that you're reasonably confident about – 100%, five-year reserve replacement.

I just wondered, behind that reasonable confidence, what assumption you're making about the book-ability of [inaudible] resources.

OK.

I think, on the first one, I think I've outlined how managing the cash side of the balance sheet and on the oil price, I will just not answer questions and then turn to speculation of what oil price we are positioning our balance sheet.

I think we are positioning everything for the long-term growth and for competitive shareholder returns.

On the RRR, what we said is actually not reasonable confident.

It will be changed into strategy and presentation.

We said we are shifting the whole thing around and the RRR is an outcome of our investment policy, investment position making.

And that will then actually give off the outcome.

And as you also said, Fred, is we are optimizing the 60 billion barrels of resources, which we have irrespective if they are accounted for on an SEC basis.

Because otherwise, you would never invest in oil sands if you do that.

You will not probably invest in some other unconventionals, which will come down the road.

So, as I've said with Pearl, I will give an update when we have the annual reserve season.

On the RRR, I think we still give the same sentence, like if you reach the goal, we are looking at it still and we are somewhat – I'm looking for the words at the moment, but somewhat – there is a fair prospect.

That's what we use.

That's – it's a fair prospect that we get to the 100% over these years.

But it is an outcome and then if decide deliberately to postpone project, that will happen in time.

Thank you.

Thanks.

The next question comes from Mr. [David Klein].

Please state your company name followed by your question.

Hi.

It's David Klein from ABN AMRO.

Two things.

Firstly, on Russia.

Can you give us progress reports on negotiations with [Gas Pro] on [Zacklin to Zacklin Oil].

And on talks with the Russian authorities about the Zacklin to cost overruns.

And secondly, could you update us on your current appetite for engaging in a mega merger?

The swap was, beside the memorandum of understanding a year ago, then we said in 2006, we will discuss the details of the swap and that's exactly how it takes place.

And as you know, the year is not over.

The costs – and that includes the cost overruns during the building of the [inaudible], we have to – that is according to the [greet] process with Russian authorities.

We have to submit all our cost data to the government and the government has, on various occasions, repeated that they stick to the process and that is what we see.

Then your last question was about consolidation.

That was probably reflected on the same newspapers as I read yesterday.

We have nothing to say about that and we don't – and I don't go on any speculation about that.

Operator?

Thanks.

The next question comes from Mr. Colin Smith.

Please state your company name followed by your question.

Good afternoon, gentlemen.

It's Colin Smith from Dresdner Kleinwort.

Peter, it's another one for you on Pearl.

Three questions.

First of all, can you just confirm that the PSA terms are unchanged from those you signed up when you originally envisioned the project was going to cost $5 billion and, therefore, that you will make the same return on the expanded CapEx involved in the project now.

Secondly, could you just confirm what the conversion rate for dry gas into GTL is expected to be in the plant.

And the third thing was, I think you mentioned 320,000 barrels a day.

If that was a daily production rate, I'm not quite sure how it squares with the 1.6 billion cubic feet a day mentioned in the report because I'd get that coming out at about 275,000 barrels of oil equivalent today on a 5.8 to one conversion ratio.

Thank you.

OK.

Thanks, Collin.

On the first one, we have a confidentiality agreement in place with [inaudible], so I can't give you comments on the PSA.

On the second one, let me just take you through step by step.

On the upstream, some 1.6 billion cubic feet per day of [well head] gas will be produced from the north field and transported to shore where it will be process to produce approximately 120,000 barrels per day of [condensate], [inaudible] five petroleum gas and [inaudible], leaving dry gas, which will be used at [inaudible] for the GTL plant.

Over the lifetime, as I said, the integrated Pearl project will produce upstream resources of approximately three billion barrels of oil equivalent.

The downstream, the dry gas will be used as feedstock for a new onshore integrated GTL complex, which will manufacture and additional 140,000 barrels per day of clean, liquid GTL products.

And the complex, the burn complex will therefore consist of 270,000 barrels per day GTL trained and associated facility.

So, that's how we look at it and that's how also read it, how we can communicate and further I cannot go.

Peter, I'm not asking you to talk about the terms of the PSA.

I'm merely asking if they changed.

And I think I cannot talk about that, but I have talked about a lot on how we positively look at the returns and the cash flow, at the unit cost rate, which we have.

It's the biggest plant we produce.

We keep 100%.

So I think that gives you the right insight on how we look at these projects and how we look at the terms which we have received.

Thank you.

Thanks.

The next question comes from Mr. Neil McMahon.

Please state your company name followed by your question.

Hi.

It's Neil McMahon with Sanford Bernstein.

I've got three questions.

Two on U.S. gas and one on [Sacolin].

First of all, I'm struggling a bit with your U.S. gas realization price of $7.36 per MCF versus the Henry Hub price of nearly a dollar below that.

Virtually everybody else that has reported has reported it at this kind to Henry Hub price and yet you've got a premium in there.

Does that suggest that you were hedging in the first quarter some of the volumes that you produced in the second quarter?

And the second part of that question is how are you viewing the U.S. gas market up to minute in terms of acquisitions?

You had talked in the past about doing small, under $10 billion acquisitions.

How is that looking today and I've got a follow-up on Sacolin.

OK.

I think we have no hedging policies.

That's very simple.

It's a geographical mix into production and the good realization, which you have seen now, which you also have seen before.

So, we are actually capturing quite well.

I think that's the only way I can explain that because we have clearly been above, let's say, the Henry Hub prices, and, as you say, some of the competitors.

On the acquisition side, if – we will just not comment on any acquisitions anymore.

We have outlined our organic strategy.

As I said back in May, we need – we had actually 90 slides outlining that and I think that's where we will concentrate.

Just on those gas numbers.

Are you including, in gas units, the liquid spring in that or something to hit higher prices?

I don't think we are including the liquid stuff, but I will recheck that.

But that's not what we do, actually.

But on presumes, as you go forward and start development the Wyoming and various onshore, which trade out at this kind, that – this number, this premium in gas is going to go down in the future.

I think you have to wait until we produce and then we will have that discussion.

I just have a final bit on Sacolin.

The Sacolin to oil exports from news reports seem to have been held up in July and late June.

Just wondering what the latest status is on Sacolin to your oil production and oil export at the minute.

And was any – or do you expect that to impact the third quarter results?

I pass it onto you.

They'll say it temporarily holds [inaudible] platform, which produces, as you know, over the summer and the [inaudible], but not on [the ice].

As far as I know, the thing is back on stream.

OK.

Great.

Thanks.

Thanks.

The next question comes from Mr. [Peter Nicholas].

Please state your company name followed by your question.

Hi.

It's Peter Nicholas, Tristone Capital.

A couple of questions, if I may.

First off, when you talk about these long life projects and what they're doing in terms of future long-term cash flows, I guess it's also probably moving your investment program in terms of payback and investment further out into the future.

And was just wondering how you sort of handle that.

Is that going to be done by project finance and debt or does it imply that you'll be looking for sort of more short-term return projects elsewhere?

Second question was going back to the oil sands and your comments about technology, is that the driver for where you've invested directly from the [inaudible] into things like [Sure Northern Energy] versus what you do via Shell Canada?

Or is there another reason for having your activities there through sort of different corporate entities?

And the last one was – I think the recent media reports were quoting you as saying that you're interest in Venezuelan heavy oil and just wondering where that's due and how fast we might see something develop there?

I think, on the first one, I think, if I understand the question correctly, you're looking or you're asking how we are optimizing our portfolio.

And I think that's the [inaudible] company does operate to optimize the portfolio so that the short-term, medium-term, long-term cash flow streams do allow you to actually optimize your shareholder return and at the same time, actually, grow long-term.

Yes, we have a steady stream and you find in our strategy presentation, actually, a charge which outlines between now and 2014 how much more we are going to have in terms of production from these long life projects over the next eight to 10 years.

And I think that's the way they are optimizing it.

So, as we also said, we will keep conventionals quite firmly on our agenda.

Some of the big projects are conventional projects in that sense like Sacolin, like [inaudible].

And the unconventionals will be 10% to 15% production by 2014.

And therefore, conventionals, a mixture of long life plus a rather more short-term, like Gulf of Mexico, like North Sea assets, will still fill part of the portfolio.

So, you do that on a portfolio basis and you allocate your cash in such a way.

I think the second one I give to Jeroen.

Yes, and as Royal Dutch Shell plc, sort of the company faster than the [inaudible] in Canada and we have the operating Shell in Canada as well.

And indeed, why did we buy that from Royal Dutch Shell plc?

Because, indeed, technology considerations played a role.

Secondly, Venezuela is – I was just down there myself and indeed we discussed with the government better than our possibilities for our technology and that is called an area as [Faja], which has this very – the kind of super heavy oil.

We think that one day we may have appropriate technologies to have good developments over there as well.

I think we have to go to the last question.

Thank you, sir.

The next question comes from Mr. [Edward Westlake].

Please state your company name followed by your question.

Yes.

Good afternoon.

Last question.

There's been a lot answered already.

But can you just update us a little bit in terms of your rig coverage, particularly as we look out into '07, '08?

And just on the gas side, just concerned a little bit about progress on some of the re-gas, say Gulf landing and [inaudible] and Italy, just to match up with the gas – re-gas – of the liquefaction projects that you've got obviously coming on in Nigeria and in the Middle East.

OK.

I'll take the recoverage.

We are very proud, actually, of having started this very early last year.

We took a lot of rigs on board to cover our '06, '07 and '08 and partially also '09 needs as prices which, compared to today, are seen as very favorable prices.

So I would go as far as '07 and '08 is more or less covered.

Partially also '09.

And from that point of view, we have reacted early and we are very pleased with that, if you look at the prices which are paid today.

Regarding the re-gas terminals, I think we are pleased.

As you know, we are building the [Bacha].

We are involved in the [Bacha] one – [Bacha], California and Mexico.

We are in [Altimina] as well there.

That's going OK.

We have our [inaudible] terminal operating.

We had the first ships going in there a few weeks, months ago.

We are looking at various other U.S. terminals.

For example, in [Alba] Islands, we are looking at expansions and we are also looking at Gulf landing, but also at Long Island, et cetera.

So, we are pleased with that.

Italy, in our opinion is OK, moving forward.

So, I think we are also covered there for the European or some part of the European market.

So, thank you for your questions.

I hope that I was not cut and dry on too many questions.

Our message today was we felt we had an underlying good second quarter and that, in spite of the troubles we had in Nigeria, and indeed [inaudible] earnestly finally.

But if I look at the total of operations and project development, how we are constructing and how we do our business development, I really feel that we can say we have an – we had a satisfactory second quarter or even a good second quarter.

As well, the message is we think we have a very simple and straightforward strategy, a more upstream, profitable downstream and I think that you all see how we are developing that – not only words but into reality to how that we shape a very good portfolio of assets for the next decade.

Thank you very much for your questions.

Thanks.

Bye.

That concludes the conference call.

Thank you for participating.