殼牌 (SHEL) 2011 Q2 法說會逐字稿

Welcome to the Royal Dutch Shell Q2 results announcement call.

There will be a presentation, followed by a Q&A session.

(Operator Instructions) I would like to introduce our first speaker, Mr.

Peter Voser.

Please go ahead.

Thanks, Operator.

And good afternoon, and welcome to the Royal Dutch Shell second-quarter 2011 results presentation.

Simon and I will take you through the results and update you on where we are with strategy.

And there will be plenty of time for your questions.

Let's look at the cautionary statement first.

The world is in an era of important geopolitical transition, some volatility, and intensified economic cycles.

Emerging nations like China and India are going through rapid development, and OECD economies have financing challenges.

All of this comes at a time when access to low-cost oil and gas is more difficult, and there are questions in society around environmental impact.

This is a complex and volatile landscape for the energy industry, and an opportunity for Shell.

In 2010, we mapped out a three-year plan for Shell through 2012.

It focuses on three strategic priorities -- improving our near-term performance, growing the Company by bringing new projects onstream, and generating new options for future growth.

I am pleased to say that we are making good progress on all of these themes.

Our Q2 2011 CCS earnings, excluding identified items, were $6.6 billion -- an earnings per share increase of 52% year on year.

This improvement comes despite pressure on the refining margins and low North American natural gas prices.

Underlying upstream volumes were good -- up 2%, and we are continuing to work on our costs.

We sold $1.3 billion of non-core assets in the quarter, $4.4 billion so far this year, as we improve Shell's capital efficiency and upgrade the portfolio.

2011 is an important year for Shell's growth program, and I'm very pleased that we have started up three large projects -- two in Qatar and one in Canada.

These projects underpin Shell's targets for cash flow and production growth through 2012.

Now looking into the medium term, we have launched some exciting new projects this year, with 9 new FIDs -- final investment decisions, and we have finalized the Raizen downstream joint venture in Brazil, which is a leading biofuels player.

So, overall, good progress on our plans in 2011.

Now, let me give you some more detail.

Now, continuous improvement is embedded in our operations and activities here at Shell.

This is all about small and incremental initiatives to enhance our performance and commerciality.

It's things like simpler structures and standardizations, for example, in contracting and procurement.

The opportunity is, in total, around $2 billion of potential.

Now, let me give you one example.

Shell drilled over 200 [gas and CVN] wells worldwide in 2010.

So, how do we work on costs, then?

We are establishing a 50-50 joint venture with CNPC, which we expect to substantially improve our competitive cost position in onshore gas drilling.

The JV is intended to develop and own, standardize and automate the drilling equipment, sourced from low-cost suppliers for drilling and completing new onshore wells.

This is intended to be used for high-density drilling projects, both in China and in other countries in the future.

Continuing this performance focus, let me update you on capital efficiency.

Disposal of non-core assets is an important element of Shell's capital efficiency and portfolio enhancement program.

We have sold $32 billion of assets in the last five years, which is a rollover of nearly 20% of our capital employed.

We completed $1.3 billion of asset sales in the quarter; that's over $4 billion so far this year.

And there is more to come in the second half of 2011, as we reallocate capital to new growth positions.

Now, turning to that second leg of the strategy, which is growth delivery.

We have some 20 new projects startups planned for 2011 through 2014 -- some 800,000 boe/d of new production.

These are the new projects which underpin our cash flow and production growth targets.

Three of these a new projects -- Oil Sands in Canada and LNG and GTL in Qatar, are now onstream.

These three projects alone, at peak, should reach over 400,000 boe/d for Shell, or over 10% of 2010 production.

Pearl, Qatargas 4, and AOSP 1 contributed some 170,000 boe/d in the second quarter of 2011.

So, good progress, and just under halfway there ramping them up.

These startups reflect some of Shell's unique strengths in the energy industry today -- innovative technology, integration across value chains, and creating long- lived returns for shareholders.

So, these are exciting times on the growth side.

Now, turning to the third strategic theme, generating new options for future growth -- and this is really about 2013 and beyond.

So far this year, we have taken final investment positions on nine new projects.

Prelude Floating LNG is the largest of these new developments.

This is an innovative development solution for smaller-sized [strand and gas feeds], and the first in our industry.

Taking these other interests in Australia, we now have some 8.3 million tonnes per annum of LNG on the construction there -- another 40% [stead] on top of our worldwide capacity of 20.5 million tonnes per annum onstream today.

Now, when you combine our 2011 progress of new projects with the five investment positions we took in 2010 -- Mars B, BC-10 Phase II, North American tight gas, we have matured over 400,000 boe/d of new production in the last 18 months.

So, 400,000 barrels per day of new capacity coming onstream in '11, another 400,000 barrels per day going into construction.

This is all about sustained investment for growth and shareholder returns.

Now, let me turn to downstream growth.

On that theme, let me highlight that our Brazilian joint venture with Cosan, which is called Raizen, went live in June this year.

We have merged our Brazil marketing operations with Cosan's portfolio, and the JV will have about 4,500 retail sites combined -- a top-3 player in Brazil.

All of these will be branded as Shell sites, and offer Shell's distinctive suite of fuels for customers.

To give you some perspective, Brazil on 100% basis is now about 10% of our retail network worldwide, and one of our top-3 retail countries.

Raizen also makes Shell's first move into substantial biofuels production.

The Company is the number-1 bioethanol player in Brazil, and it could more than double in scale in the next five years.

To give you an idea about size, Raizen's EBITDA would currently be around $2 billion on an annualized 100% basis.

Now, we will equity account this JV.

So, again here, good progress on strategy development, assets sales on track, new projects startups, new investment positions in upstream and downstream.

Now, over to Simon to talk about Q2 results and update you on the financial side.

Simon?

Thank you, Peter.

I will start with the macro environment.

And if you look at the macro picture compared to the second quarter of 2010, oil and gas market prices have increased from year-ago levels with broadly similar Henry Hub.

The discounts of WTI to Brent widened to $15 in the second quarter, and that compared to less than $1 in the second quarter of 2010.

And this, of course, impacts our oil realizations.

Industry refining margins diverged in the quarter with improved margins in the US, partly as a result of that WTI; but sharp declines in Europe and Asia, where we have some 60% of our refining capacity.

Chemicals margins increased from a year-ago level, although the margins were weaker in Asia.

Turning now to earnings -- our CCS earnings for the quarter, including identified items, were $8 billion.

Excluding those identified items, the CCS earnings was $ 6.6 billion and the earnings per share increased by 52%.

And that's compared with the second quarter of last year.

On a Q2 versus Q2 basis, the quarter was characterized by higher earnings in upstream and similar levels in downstream.

The cash flow from operations was $10 billion.

The dividend for the quarter remains at $0.42 per share.

The scrip dividend [takeup] was equivalent to $800 million for the first quarter, and we are offering the scrip dividend again for the second quarter.

And now, let me move on to the business performance in a little more detail.

Firstly, the upstream.

Excluding the identified items, upstream earnings were $5.4 billion in the second quarter; and that's an increase of 66% against the same quarter in 2010.

The earnings were driven by higher prices and higher oil and LNG volumes.

And they were partly offset by lower natural gas demand, higher taxes, and increased operating expenses -- these largely reflecting the startup of new projects.

Headline oil and gas production for the second quarter was 3 million boe/d.

That's an increase of 2% when we exclude the impact of asset sales.

Looking at the first half of 2011 production, we had a positive impact from growth barrels; they more than offset the natural field decline.

There were also negative impacts from assets sales, maintenance, and demand; however, the underlying performance is good here.

LNG sales volumes grew by 14% in the first half of 2011, compared to the same period in 2010.

It's probably worth reflecting that the comparative figure against 2009 first half is 55% growth, just showing what the portfolio can do.

And that, in this particular quarter, does reflect the successful ramp-up of Qatargas 4, as well as higher volumes from Nigeria LNG.

Turning now to the downstream -- the underlying downstream earnings are broadly similar to a year ago, at $1.1 billion for the quarter.

Now, lower results from oil products were partly offset by stronger figures from Chemicals.

Our oil products earnings, they were supported by very resilient marketing and trading earnings.

That's a strong performance in a difficult environment.

However, refining was impacted by sharply lower industry margins in Europe and Asia, compared to a quarter ago -- a year ago, and these of course are important refining regions for Shell.

But we clearly saw the effects of a lower operating performance in the quarter, with both planned and unplanned downtime eroding the results.

With two-thirds of the 2011 planned turnaround now completed, we expect to see improved availability for refining and Chemicals in the third quarter, and should be at similar levels in the third quarter in 2010.

Our restructuring program in oil products continues, with plans to improve our operating performance, take out $1 billion of costs, reduce our refining capacity, and refocus our marketing portfolio.

So, those are the earnings and -- net earning to cash flow.

Cash generation on a rolling 12-month basis was $50 billion, including $10 billion of divestment proceeds.

And the average oil price over that 12 months has been $96 for Brent.

Both the upstream and the downstream segments are generating surplus cash flow after investment.

We are watching the cash position very carefully, and I am pleased to see our inflows and outflows are now moving to a free cash flow position -- albeit, of course, assisted by higher oil prices and the asset sales.

Turning now to capital spending and the balance sheet, the improving free cash flow position, combined with our capital spending and dividend programs, has resulted in a decline in balance sheet gearing.

At the end of the quarter, the gearing sat at 12%; and that compares with 14% at the end of the first quarter, continuing to move lower into our 0% to 30% range.

Now, you would expect this in strong oil price conditions, of course.

We've made good progress on asset sales, with some $4.4 billion of proceeds booked in the first half of this year.

And this, combined with the ongoing asset sales, means we are comfortably on track for the $5 billion divestment target we set for this year.

The final figure for the year will of course be driven by the timings at which we close these deals.

The net capital investment for the first half of the year was $8 billion, compared with a full-year plan of $25 billion to $27 billion.

Now, our organic spending for the first half of the year is below the run rate we had planned for this year, but it should accelerate in the second half following all of those recent FIDs that Peter mentioned.

The second-quarter acquisition figures include the Raizen joint venture, but exclude the $400 million acquisition of UK retail sites that we've announced recently -- we would expect to complete around the year end.

So, those are the comments on the quarter.

And with that, Peter, hand over back to you.

Yes, thanks, Simon.

Let me summarize before we go for your questions.

Our performance in the quarter underlines that we are delivering on our strategy.

We are making good progress with our three strategic themes -- that's performance focus, growth delivery, and maturing new growth options.

The startups this year lay out good foundations for financial performance in the quarters to come.

Investments such as Pearl, Prelude, and Raizen are unique in our industry.

They are a great testament to our staff and our stakeholders, and reflect Shell's core strengths.

Shell adds value through innovative technology, sustainable growth, integration across value chains, and by creating long-lived returns for shareholders.

This is a competitive and innovative strategy.

So, with that, let's take your questions.

Please could you -- could we just have just one or two each, so that everyone has the opportunity to ask a question.

Operator, please poll for questions.

Thank you.

We will now begin the question-and-answer session.

(Operator Instructions) Lucy Haskins, Barclays Capital.

On the integrated gas contribution for the quarter, very strong.

Could you give some [theory] in terms of how much of that was coming from -- we've seen the volume improvements, we've seen the margin improvements.

How much of the margin improvement were the [adjusted lags], sort of oil price effect coming through?

How much of it was arbitrage opportunities you were able to exploit during the quarter?

And how much of those arbitrage opportunities do you think could be sustainable, now you're building perhaps a little bit more flexibility into your LNG portfolio?

Very strong contribution, indeed, reflects our volumes are up very significantly, largely driven by Qatar and Nigeria, both of which have some optionality in them.

Proportionally, our ability to take the gas to a more attractive market has indeed increased.

I wouldn't necessarily call them arbitrage -- it implies that they're non-structural.

We are able to take the cargoes in over quite long periods of time, and in particular, divert some of those volumes in from both plants that were initially targeted at the United States into more attractive markets.

I don't have a great [sense] specifically from arbitrage price and volume, because all of them actually interact almost by definition.

In fact, the rapid startup of Qatargas proved particularly advantageous, because we had more volume than we expected on which we were able to effectively take advantage.

The number of diversions was roughly double year-on-year, around 30 cargoes.

Pretty significant; and primarily into Asia and the Middle East.

Strong performance, quite a bit is replicable.

Of course, the arbitrage between Henry Hub and crude-related pricing is particularly attractive at the moment.

I would highlight that in Europe the actual spot [link] prices in Europe, the MVP was at least double Henry Hub, typically trading $9 to $10.

Generally an attractive environment for LNG.

Kim Fustier, Credit Suisse

Firstly, on Iraq, could you please comment on the Basra gas deal that was initialed a couple of weeks ago?

What are the next steps from here?

And when can you start thinking about LNG?

My second question is on China gas.

Could you maybe give us an update on your shale gas drilling activities, especially in the Sichuan Basin?

Have you fractured the wells and tested them for flow rates?

I'll take Iraq, and then Simon can do China.

We are very pleased of having signed the contract in South Iraq Gas.

There's still more hurdles to go.

The prime objective in the near term is clearly to actually capture [flared] gas and make it available domestically.

And then, over time, as production ramps up, obviously we'll go into potential export schemes.

I would say they are a few years down the road, and I think that planning would still take place a little bit later.

We will concentrate first on getting the deal over the line; and once we have it, then we will capture the gas -- and actually it ramps up, I'm sure we will talk soon about exporting gas, then, as well.

China, overall, just to reiterate the overall program there, we actually have, of course, the 1 operating concession, Changbei; we have 2 larger -- or 1 tight, 1 shale gas concession, 4,000 square kilometers each, in Sichuan Province; and we have 2 CBM activities further north in Shanxi Province.

Over that whole portfolio, the plan was to effectively spend over $400 million drilling this year, 15 to 17 wells.

We are drilling in both of the Sichuan provinces at the moment.

It's great to be able to get up so quickly -- less than 12 months after we made the first agreements on the activity, with our partner PetroChina.

Their excellent safety and reliability performance to date through their contractors gives us great confidence for the joint venture that we've just announced.

Yes, we've fractured the wells.

Yes, all of the basins that we are looking at are looking like their original prognosis.

What I can't do is really give you any figures, partly because it's a joint venture, and partly because it's still very early in the activity.

Our aim is to complete that -- export what is truly an exploration program during this year, and define the next phase of appraisal for next year.

But hopefully, we will be able to lift the level of spending there next year.

Iain Reid.

Couple questions on the Gulf of Mexico.

Could you update us on exactly how many permits you now have, and what you expect to be drilling this year or next year on the basis of your exploration and development program?

And when do you think you're going to be able to recover the 50,000 barrels a day which you have lost due to the moratorium?

I share this answer with Simon.

I give you a little bit bigger picture, and then he can go into the barrels, et cetera.

We are very pleased with the progress we have made so far, albeit I have to say it's still somewhat slow in the way we get permits; so that needs to accelerate.

The 5 rigs now operating again.

I would say, from an operational point of view we are back to operate normally; but obviously we are still down in terms of barrels, and Simon can take you through that.

All in all, pleased with the progress.

Could be faster.

We are hoping to develop things back to where we would like to be, as we have outlined to you in our strategy presentation last year, but earlier this year.

So, we are still in a catch-up mode on that side.

So, to the barrels, over to Simon.

In total, we currently received 3 exploration plans, a development plan, a couple of additional well permits.

The exploration plans typically include some drilling permits, as well.

We said we'd be up to 50,000 barrels a day short on production, relative to what we otherwise would have been for this year.

That level of permitting and drilling means that we can basically confirm that, that we were 50,000 short of where we might have been.

What we are likely to produce in the Gulf -- subject to hurricane activity, of course, is around 200,000 barrels a day this year; so, it should have been 250,000.

That's quite a significant impact on all of our earnings, the way that you do the analysis.

Not down from 2010 and 2009 -- 2009, the last year pre-hurricane, was 270,000.

So you can see quite some impact.

As we go forward, we expect to make up some of the gap.

The comparison against what we would otherwise have achieved becomes rather less meaningless as we go forward, as we adjust our drilling plans to the opportunities that are currently available to us.

But we should certainly make up in areas like the (inaudible), and (inaudible) we are working over wells on the operating platform.

We should see some narrowing of that gap in 2012 built in already to the projections that we have been making, even though we made the original projections before the moratorium.

Jon Rigby.

A couple questions.

The first is on the megaprojects you brought on this year.

Obviously, the volumes are starting to come through.

But if the upgrade, for instance, on Athabasca was just starting up, and presumably not all the products are being made in Pearl yet, even on the first [train] -- indeed, I guess you're still making them, put them into storage.

Was there any real meaningful contribution from either of those 2 projects to earnings and cash flow in the second quarter?

Is there a latent positivity on earnings and cash flows into 3Q and 4Q?

And then, the second question is just on Chemicals, which seems to be having a remarkable renaissance over the last couple of years.

I wondered how much of that was down to the US business.

Is there something structural around profitability in the US chemicals business that will stick around until -- if or until US gas prices close on international oil prices?

Let me start with the first one.

I just repeated (inaudible) we had 170,000 barrels in from the 3, that includes Qatargas 4, which is ramped up fully now and then the other 2 is coming into the quarter, total capacity more than 400,000.

There is quite a bit to go in the quarters to come.

Now, I give you a summary of the 3 and the impacts in the quarter.

That will be Pearl, Qatargas 4, and AOSP.

Apart from the production, we had roughly [$500,000 million] (inaudible) in it.

And cash flow-wise, as you are ramping up, as you rightly say, the stocks -- we are obviously ramping up working capital.

So, cash flow-wise, it was roughly $100 million in there from all of those.

And some [were still] a very late start up, they were clearly negative on the cash side, because we are just building up the working capital.

I think on the Chemical side, I am very pleased on how the Chemicals business has turned around, specifically in the United States for us, because they are really moving us away from a competitive disadvantage of being liquids-driven in the (inaudible) to actually being (inaudible)-driven has really made a big turnaround for us.

We also have improved, clearly, the cost base -- not just in the United States, but across the world.

So, I think we are structurally much better positioned now.

And given where the gas prices are, et cetera, et cetera, I think you can expect a good performance and a strong continuous performance out of the US -- obviously, depending on pricing structures in the market.

But the underlying operating performance is very strong.

Now, based on that, I just take a little bit wider view on this.

As we said previously, we also are looking now at how we can actually use the Chemicals [field stream] and linking that back to our tight gas and unconventional gas positions, which we have in the United States.

We are also looking into how we can add further value further down the road.

But I'm talking about a few years down -- really down the road.

So, very pleased about the strategic and the operational shift which we have made in the US in Chemicals.

Peter Hutton.

Two questions, if I may.

First, on the acquisition of the 30% of the Abadi Floating LNG.

Can I check how that fits into the portfolio of other LNG [projects] you have in Australia, heading in the same direction.

2018 -- does that jump up ahead of some of the others that you have?

And is it likely to come ahead of Arrow?

And does it use Shell generic technology?

The second is on share buybacks.

I'm not arguing for a greater share buybacks when you're making a very strong point about reinvestment for future growth.

But the scrip dividends was to give balance sheet flexibility, and the balance sheet is extremely strong.

I notice that you're not going into the market to buy back the shares to cover the shares that people are not taking -- they're taking a scrip.

Are you expecting to be more aggressive in that, i.e., that the scrip dividend element should be neutral in the future, and quite quickly?

The dividend policy about the overall financial framework does require us to buy back scrip or shares issued under the scrip program to offset the dilution.

We will meet that commitment; clearly, in cash terms, we are in a better position to do that.

But I don't want to be signaling too much ahead of the market, but we will meet that commitment.

There are no current plans to go beyond that commitment.

I think first of all we are very pleased with our progress in Indonesia, together with impacts to buy into that LNG project.

So, very pleased about that.

And they already operated, but I think we can bring some help and some advice and skills to that.

On your Australian question, then, I think we are concentrating on Prelude.

As we have taken FID, this is our strong, strong kind of focus on.

Now as you know, we have so many of the other projects there, like Sunrise, where we have already agreed with venture partners that we will use our technology.

We are also working on Arrow, where we have said we will actually target LNG seam in 2011.

We are talking there around the first phase, which should be two [trains] and 8 million tonnes per year LNG.

We haven't been forthcoming with exact dates on that further down the road.

We will talk to you once we are further down and then have taken it by year, et cetera.

We will develop these things as separate and single projects.

I think that's the way you should look at that, and not link them in to other areas.

[Mr.

Griffith].

A couple questions for you.

The guidance you've given previously on cash flow from operations, and $60 and $80 a barrel -- are you likely to see any change in that?

On the capital employed at work, were you able to give any indication of what capital employed is now at work, and where you might see it normalizing at?

Thanks for the questions.

On your first one, there is really no change to that.

We have said in $60 and in the $80 world, it's 50% up, or at least 80% up between '09 and 2012.

That really means we are aiming at the $43 billion at the higher end and $36 billion on the other side, if you'll take the lower amount.

So, no change to that.

It's also reflecting the production targets which we have given, which is 10.5 million barrels per day.

And this is all we'll be working for at the moment and then into 2012.

On the capital employed, I give that to Simon.

The capital employed, just over $200 billion.

Typically, we have had over $60 billion of that not yet employed -- either work in progress or effectively signature bonus, acquisition premiums, et cetera.

The coming onstream in Qatar and Canada will have reduced that amount unemployed by close to $20 billion, as of the end of Q2.

And of course, it wasn't actually in service for very much of Q2 -- in fact, weeks, literally.

So, we're effectively more productive, but not yet producing at full (inaudible).

The production was only up 170,000 after the 400,000 on the three big projects.

And on the earnings -- very little cash flow; and these projects together -- in Qatar alone, were projected at close to $4 billion at $70 a barrel.

And another $1 billion in Athabasca at $70 per barrel.

So, there's still quite a lot to come there.

Bradley (inaudible).

It's Fred Lucas at JPMorgan.

Couple of questions.

Recently visited Rumaila in Basra Province, Iraq.

There seems to be some confusion there as to what actual rights the Basra gas deal might give you, with respect to the gas that's currently being [flowed] by Rumaila, which is very significant.

I wonder if you could clarify that point.

Second question relates to LNG projects.

First of all, Prelude.

I think Malcolm Brindle has indicated costs there of around $3,500 per tonne, which would point to total CapEx north of $12 million to recover just over 500,000 million barrels.

So, it looks quite expensive -- reserve recovery at over $20 a barrel.

Should we expect projects like that to make a return on the first project, or does it need the boat to move on to a second project to make an adequate return?

And then, finally, on your coal bed methane LNG project in Australia, today we saw the FID for APLNG, so that leaves you fourth in the queue.

Don't you think that's quite a precarious position to be in, given emerging inflationary pressures in Australia, more generally upstream?

I think on the first one -- I think I have heard the same kind of description from what you just more or less quoted.

I will not go into that discussion at this date.

We have initialed a deal, or signed one, which is now subject to 2 further approvals.

Once we are through there, then we will inform what it exactly includes, and then I think it becomes clear to you, as well.

I leave the floating LNG to Simon -- I deal with Arrow, which was your third question.

I think we said from the beginning that we are not in a rush here.

We will develop this.

We see the rush into quite a few FIDs by others.

That, in our opinion, will drive costs up, and I think we are quite happy to go later into [feed] and then FID, and be already behind some of the others, because we think that gives us a cost advantage.

As you know, this is a joint venture with CNPC, which also gives us access to cheaper China (inaudible).

We take it from that side; but you can see us progressing steadily towards the FID on this one.

Let's also remember we have floating LNG, we are working on -- divert other projects in Australia at the same time.

So, our annual spend will be in the $3 billion to $4 billion in Australia alone over the years to come.

And I think let's work carefully our way into that.

And then, I pass on to -- the financial performance, et cetera, questions on FLNG to Simon.

On floating LNG, probably it's 3.6 million tonne per annum project.

What we said -- Malcolm said, is $3,000 to $3,500 dollars per tonne of capacity.

What we have not done is given any specific CapEx for this project.

What we have indicated is it's economically similar to other large LNG projects, greenfield ones, in Western Australia -- Gorgon.

Or, in fact that the CBM projects, prior to the inflation that you just mentioned, of course.

And the returns, therefore, are good.

We will use this particular vessel to produce the Prelude field, and likely to other fields close by.

Thereafter, we will have probably a couple of decades of useful life left, after which we will already have gotten a very attractive return -- also, $20 a barrel, I'd just point out, isn't such a bad cost in a relatively attractive fiscal environment and $115 oil.

It's pretty good at $70, as well.

Overall, you have to look at the commercial turns, the quality of the customer contracts, to get the economics.

And lastly, I would say -- yes, the first one does cost a bit more; but you can be fairly sure the second and the third and the fourth, they will be a bit cheaper.

Could I just clarify -- on the Arrow project, you're saying that into an inflationary cycle, that you commented on yourself, is underway -- that the last of 4 such projects could be cheaper than the first 3?

Yes, once certain things come onstream, you can actually benefit from, let's say, service industries or other industries who have actually ramped up their capacity and their capabilities, that you then can contract in there.

And we have the possibility through our Chinese partner to source things in a slightly different way, which also will help.

And we are building up this global wells -- JV with CNPC, et cetera, et cetera.

I think we are doing all what we need to do in order to have an attractive, profitable project, which is another (inaudible) to something which is new, pretty new, for us as well.

So, this is our style of doing it -- we take our time, we learn it, and then we move slowly, and then ramp it up.

Irene Himona.

First of all, in all your products -- a sizable refining loss in Q2.

Is it possible to split the impacts on earnings from low margins versus low volume for maintenance?

And my second question, on cash flows.

I think Simon mentioned the rolling 4-quarter $50 billion operating cash flow on an oil price of $96.

The oil price is well above your planning range.

I don't know if it's possible to adjust, but can you give an indication of what the gap is at your planning range, versus the target, please?

No, I can't really give you a split between margins and the volume loss.

$600 million was the overall loss, and the actual volume loss was probably the larger contributor, in terms of relative to previous years.

On the cash generation, what I said was $50 billion including the divestment proceeds -- so, that was around $10 billion.

It was about $40 billion, in terms of [CFFO]; so, we are on track, but we are not yet there.

And the key factor over the next 12 months will be the ramp-up performance of the main projects.

As I noted, almost no cash flow so far, but $5 billion between them capability at $70.

So, that's the biggest swing factor.

The other thing, of course, is we had said the 2012 targets -- expected, I think, a better refining environment than we've seen in the past 12 months.

And they were originally premised at a $6 North American gas price -- which is higher than today.

And you can take your own view of whether that's likely next year.

We are committed to meeting the cash flow generation targets next year.

I think, actually, indirectly have sold quite a bit of barrels which we have sold and still achieved 3.5 million barrels.

It also gives us an additional challenge; but as Simon says, we are well on track to achieve it.

Lucas Herrmann.

Can I just carry on the theme of refining and try and better understand why it is that the business seems to be suffering such a degree over so many quarters of unplanned downtime.

The loss again this quarter is, I'd say, surprisingly large.

And secondly, I wonder if you could talk around North American gas production and the seeming lack of progress in terms of growth there.

I'm not sure to what extent it's influenced by the divestment of the Vicksburg or the Texas assets, but Canadian production doesn't seem to be moving north, either.

What 's actually happening in terms of drilling spend and intention at the present time, relative to the targets that you set out in November of last year?

On the first one, we are working on 3 key issues in downstream -- and therefore, in manufacturing, which is really the [first] (inaudible) portfolio which we have (inaudible) quite far down the road.

We just announced another one a few days ago, that we are switching the [Klein] refinery into [a terminal].

So, that's clearly making good progress, and I think we are getting there.

The second one is about costs in the system and the simplification of our processes in order to actually get a lower cost base -- and therefore, also, a more agile refining system.

I think we are on track there.

Obviously, not yet done, because quite clearly that is another -- a one- or a two-quarter project, actually a little bit longer.

And the third one is, then -- clearly, it's on the operating side.

So, actually, constantly achieve our internal targets, which you have on op time, on utilization -- so, total capacity, but also unplanned downtime.

I think the system has performed okay in some quarters, it hasn't performed in some others.

And that is part of our improvement program.

If you ask me for this quarter -- did we leave money on the table?

In some areas, yes, we did.

And that's part of our refocus on getting the manufacturing side up to speed.

But I will have to say, having 60% of our assets in Europe and also in Asia has clearly given us a big disadvantage.

Not being in the WTI area, to benefit on that, has also given us a disadvantage; and one needs to take that into account.

I would say we are on track.

There is more to come here and more to do.

When you say you are on track, you on track for what -- to achieve your 10% return on capital employed target at the bottom of the cycle?

That's correct, that's what I am saying, Lucas.

Yes.

Then capital employed has gone up by $10 billion as well over the last year.

We are clearly investing -- for example, in Port Arthur, et cetera, et cetera.

That's correct, yes.

But we stick to what we have set out as a target.

Then we also say that, looking at manufacturing in isolation or refining in isolation in the downstream business is not always the only way to look at the business.

Yes, we do run it that way, and we put the pressure on it.

But you need to take the trading and the marketing integrated value chains into account when you optimize your margin streams and your value chains streams.

This comes into full flow when you start to actually cut your utilization rates of refining, and once you do not always look at that in an isolated way.

I know this is difficult for you guys to do, because we don't give you those numbers.

But just be assured that we are actually taking a fully integrated look at all of this, and we see our supply and trading and the refining business like that.

The (inaudible) over to North American gas, I give that to Simon.

The actual onshore gas volumes are down, yes, from [1.2 bcf to 1 bcf] per day.

The reduction is driven by a divestment of the South Texas volumes.

The program this year is pretty much on track, although we are at the lower end of the intended investment range, simply because the price is in the $4 range at the moment.

We are there investing to produce in the Haynesville, in the Grand Birch, we're doing a fair bit of appraisal work in Marcellus and the Eagle Ford.

In both Grand Birch and Haynesville there's quite a bit of drilling, leaving gas behind pipe, as we have not brought the infrastructure online.

Drilling has run a bit ahead of the production in the year to date.

We're overall still very much on track for that medium-term target across the Americas -- building up a much better understanding of what is required to most economically develop Grand Birch and Marcellus, in particular, because they are the big drivers.

Alejandro Demichelis.

Couple of questions.

The first one is, you went into a lot of detail in terms of the 50,000 barrels that you are leaving in the Gulf of Mexico.

Maybe you can give us an indication of what's the cost of leaving those barrels -- not just the barrels not producing, but also the cost of the time by the rigs, and so on.

And the second question is on Raizen.

You have indicated around $2 billion of EBITDA there.

Maybe you can give us some kind of indication of what's the growth profile of that business, going forward.

Raizen, we have given you an indication of the EBITDA number, which we normally wouldn't do in that side, because it's one part of one country's business, and it's rather small.

But our partner has also probably said on its website, I think I'm not going to go further into any growth projections on that.

We will update on the growth of Raizen in our strategy presentations.

I suggest you have a look at the website of our partner; you may find a little bit more there.

I'm not sure I fully understood the question, but if it's about what's the cost of the 50,000 barrels a day been, we've stopped highlighting a unique or an identified cost on a quarterly basis.

The actual foregone margin at the moment, relative to the (inaudible) -- I don't actually have it calculated.

But it's 50,000 barrels a day, you're probably talking $40 a barrel, plus or minus a bit in terms of potential earnings, at $117 a barrel.

And that's the opportunity cost, in practice.

Last year, the margin -- or the profit loss was something over $200 million.

So, it's quite a significant reduction in our ongoing earnings potential.

The question was more about the cash cost of not having those barrels, the idleness of the rigs, and so on, because that's what you're going into your P&L.

True.

It's relatively small in this quarter.

The floating rigs are all back up and running.

We have highlighted these in the past, but I don't think it's that material at this stage anymore.

Correct.

Mark Gilman.

Had a couple things.

Simon, can you give me a rough idea of how your entitlement over time is going to change on Pearl, assuming constant price?

Shoot all the questions, Mark, so we know what we have in front of us.

Okay, the others relate to portfolio.

I'm a bit puzzled by the intent to go forward with a 10,000-barrel a day de-bottleneck at AOSP.

It seems very small, and I don't quite understand how the economics can be favorable on that.

Similarly, puzzled a little bit by the UK retail acquisition, which at least in terms of per station is at about $1.5 million a station, would seem to be expensive.

Little bit of color on both those would be appreciated.

Entitlement -- over time, Mark, we have given in the past reasonably clear projections at different oil prices about entitlement to production and entitlement to cash flow They were actually at $50 and $70.

We have quite a significant cash flow while we are in full cost-recovery phase.

That takes about 7 to 8 years at $70; obviously, a lot less if we were to stay at $117.

There has been a step down, and there is a further step down just as typical -- basically, revenue-to-cost ratio trigger factors.

But the ongoing availability of production and cash flow has remained pretty significant throughout the life of the contract.

So, it's about 7 to 8 years before the first [rig here] at the $70 barrel; slightly longer at $50, and a lot less at $120.

I take the two portfolio things.

Let me start with the retail one, Mark.

I think these are stations which are predominantly in the Midlands and the Southeast of England.

It fits very well into our network, which we have.

To get to 1,150 stations in total, we see great potential with our differentiated fuels offering which we have and our lubricants offering.

These are all stations in prime markets, filling gaps which we have; and therefore, it does fit well into the UK and the overall retail strategy on a global basis.

And have met all the normal, rather stringent probability criterias which we have in downstream, specifically for marketing assets.

So, I am pleased with the deal.

On the AOSP side, I think you need to look at this in a wider sense, that we are going for developments or de-bottlenecking of various, let's say, tranches of the 30,000 to 40,000 barrels -- 30,000, 35,000 barrels.

But within that, we will have phases.

And I think we do the phases in accordance to where we get the highest bucks out of the phase early on.

I think you need to see this really in the context of the total, and should not focus on the 10,000.

You should focus on the 30,000, 35,000; but we will do it in steps, and there are smaller and bigger steps to come.

But this is really optimized around the net margin you get out of it; but also, the optimization of the capital intensity, which we have in the various steps of the de-bottlenecking.

I do agree that the number is rather small, but it makes all the sense for future parts of the de-bottlenecking that we build this one first.

Do you have a cost number on either of the tranches as you describe them, or on the 10,000?

And then, just one other on Brazil.

I don't understand the divestments that you are undertaking in terms of Brazil -- the intent to divest your 20% interest in BMSA follows on recent farmdown in one of your other Brazilian blocks.

Talk to me a little bit about the strategy there, with respect to your portfolio.

Okay, on the first one, I think [at $50,000], we reckon it will be around $2 billion, as we have said, which gives you a breakeven below $50,000.

And if you take some of the tranches within that package, they will be quite below the $50,000.

But on average, it will be $50,000.

On the second one, this is an optimization of our overall global portfolio, including the Brazilian portfolio.

We are optimizing that, and we will not keep everything in our pipeline, if you can do some farmdown to get some cash contributions, et cetera.

I think you should see this as a total, complete program which we are optimizing.

We have a rather rich pipeline at the moment for exploration, and we will not do everything totally on our own.

That's the way I look at the strategy, and it's not the only one which we do Brazil; there are other pieces, as well.

Oswald Clint.

The net income or the earnings per barrel was a bit higher than I was expecting.

It was also higher than your long-term trend, relative to the commodity, just for the upstream business.

Do you think the LNG businesses -- Nigeria, the Qatar volumes coming on, could be pushing that up?

Or is there anything else going on there?

And then, secondly, it's just the divestment -- I understand you may have exited the Swedish [aluma shield] that you were testing.

I just wanted to know if you could give us any rationale behind that.

Oswald, you're right that the LNG volumes and strong performance there, realized prices is in effect.

There is a tax mix, as well.

And if you think -- and we've been saying for some time, it's beginning to start to come through -- we've been shifting, fundamentally, the portfolio towards countries with more attractive fiscal regimes.

Once you start to get Australia, Canada, and Qatar, and the United States contributing, and maybe less from higher-tax countries such as Europe, you might see a better income per barrel going forward, as well.

And I think the second question was related to Sweden?

Yes, that's right.

I think the (inaudible) results were rather mixed, and we are not progressing, I think will be the summary.

Next question and last question.

Sergio Molisani.

Two questions on the potential gas re-export from North America, if I may.

The first one is, can you give us an update on your re-export LNG project at Prince Rupert in Canada, in terms of authorization stages and an investment (inaudible) timetable.

And what are the main factors currently under scrutiny?

Pipeline location, competition, contract agreement, and so on.

And the second question is potential GTL in North America.

You have alleged in the past that the current oil/gas price differential justifies such decision.

What could make you actually and definitely confident on the long-term economic of these initiatives?

And the last question is that the Pearl GTL is a wet gas project.

I suppose that the potential GTL in North America is likely to be a dry gas project.

How this difference could affect the CapEx per barrel of the new project in North America, compared to the $60 per barrel we saw at Pearl GTL?

I think on -- they're all a little bit in the box of future strategy, which we are obviously pursuing, in terms of looking at our very strong gas position which we have across North America, and how we can actually monetize the molecules with, let's say, the lowest element of Henry Hub exposure and the highest element of maybe liquids or other market exposures, or LNG exposures.

I will give you 1 answer to the 3.

So, we are working on all the issues you have said, like LNG exports in Canada, gas to liquids in the United States, also potentially gas to chemicals; so, there are more things which can come in here.

I think what you need on the LNG side is an export into the Asian markets, which gives you a different pricing exposure.

Therefore, it is also for Canada differentiated in terms of not having only 1 market close to them, the US -- it gives them a market opening somewhere else.

So, that's one driver, and I think we are progressing there.

You have mentioned all the elements we are working on, but I am not going to go into details at this stage.

On the gas to liquid side, what you need is gas abundantly available, you need gas which has a reasonable low cash breakeven costs, and you need to have a big liquids market.

In that sense, the US obviously has all of these elements, and that could make a GTL a possibility.

Now, we are, through Pearl, through our early investments into [Bin Tool] in Malaysia.

We are the Company with the best and the widest experience in this field; so, I would just say, looking at it, and we will update whilst we are going forward.

Any specifics on the economics like gas quality and what that means I think is for later on.

Thank you for the future strategic questions.

That brings the Q&A to an end today.

Thank you very much for all of your questions, and joining us for the call.

We are hosting a shareholder engagement covering strategy and socially responsible investments in New York on the September 9.

I hope that some of you will be able to join us in that event.

I look forward to seeing you there.

The third-quarter results will be released on October 27, 2011; and as usual, in the third quarter, Simon will face you all on that one, but he will do that alone.

Thank you very much again for calling in, on behalf of Simon and myself, and have a nice day.

Thank you very much.

Goodbye.

Ladies and gentlemen, this completes today's Royal Dutch Shell Q2 results announcement call.

Thank you for participating.

You may now disconnect.