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Royal Dutch Shell Plc. (NYSE:RDS.A)

Q2 2011 Earnings Call

July 28, 2011 8:00 a.m. ET

Executives

Peter Voser – Chief Executive Officer

Simon Henry – Chief Financial Officer

Analysts

Lucy Haskins – Barclays Capital

Kim Fustier – Credit Suisse

Iain Reid – Jefferies

Jon Rigby – UBS

Peter Hudson

Fred Lucas – JP Morgan

Irene Himona – Société Générale.

Lucas Hermann - Deutsche Bank

Alejandro Demichelis - Bank of America/Merrill Lynch

Mark Gilman - The Benchmark Company

Oswald Clint – Sanford Bernstein

Sergio Molisani - UniCredit

Peter Voser

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. Now, let's look at the cautionary statements first.

The world is in an era of important geo-political transition, strong (inaudible) and intensified economic cycles. Emerging nations like China and India are going through rapid development and OECD economies are 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 to 2012. The focus is around three strategic priorities. Improving our near term performance, growing the company by bringing new projects on stream 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 and 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 improved Shell’s capital efficiency and upgraded the portfolio. 2011 is an important year for Shell’s growth program, and I am very pleased that we have started up three large projects, two in Qatar and one in Canada. These projects on underpin Shell’s targets for cash flow and production growth to 2012.

Now, looking into the medium term, we have launched some exciting new projects this year with nine new FID’s, Final Investment Decisions, and we have finalized the rate in downstream joint venture in Brazil, which is a leading bio-fuels trader. So overall good progress on our plans in 2011. Now, let me give you some more details.

Now, continuous improvement is embedded in our operations and activities here at Shell. This is all about small incremental initiatives to enhance our performance and commerciality. Things like simpler structure and standardizations for example in contracting and procurement. The opportunities in total round to billions of dollars of potential. Let me give you one example.

Shell drilled over 200 tight gas and CBM wells worldwide in 2010. So how do we work on costs there? We are establishing a 50-50 joint venture with CMPC, 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. They 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 assets 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 the second leg of the strategy which is growth delivery. We have some 20 new startup plans for 2011 to 2014, some 800,000 BOEs per day of new production.

These are the new projects which underpin our cash flow and production growth targets. Three of these new projects, oil sands in Canada, LNG and GTL in Qatar are now on stream. These three projects alone at peak should reach over 400,000 BOEs per day for Shell or over 10% of 2010 production. Pearl, Qatargas 4 and AOSP 1 contributed some 170,000 BOEs per day in the second quarter 2011. So, good progress and just under half way there ramping them up.

These startups reflect some of Shell’s unique strength in the energy industry today; innovative technology, integration across value chains and creating long-life 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 decisions on nine new projects. Prelude Floating LNG is the largest of these new developments. This is an innovative development solution for smaller-sized strand of gas fields and the first in our industry. Taking with our interests in Australia, we now have some 8.3 million tons per annum of LNG under construction there. Another 40% step on top our worldwide capacity of 20.5 million tons per annum on stream today.

Now, when you combine 2011 progress on new projects, which defies investment decision we took 2010 must be BC-10 Phase II, North American tight gas, we have matured over 400,000 BOEs per day of new production in the last 18 months. So, 400,000 barrels per day of new capacity coming on stream in ’11, another 400,000 barrels per day going into construction. This is all about to strange investment for growth and shareholder returns.

Now, let me turn to downstream growth. In downstream, 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. On the JV we will have about 4500 retail sites combined, a top three player in Brazil.

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

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

Raizen also makes Shell’s first move into substantial biofuels production. The company is the number one bio-ethanol 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 developments, after sales on track, new project start-ups, new investment decisions in upstream and downstream.

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

Simon Henry

Thank you, Peter. I'll start with the macro environment. If you look at the micro picture compared with the second quarter of 2010, oil and gas market prices have increased from year-ago levels with broadly similar Henry Hub. The discounted WTI to Brent widened $15 in the second quarter and that compared to less than $1 in the second quarter of 2010, and that of course impacts oil realizations.

Industry refining margins diverged in the quarter with improved margins in the US as a result of WTI, but sharp declines in Europe and the 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.

Tuning now to earnings. Our CCS earnings for the quarter included 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 cost 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. Scrip dividend take up 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 high prices and higher oil and LNG volumes that were partly offset by lower natural gas demand, higher taxes and increased operating expenses, this largely reflecting the start up of new projects.

Headline oil and gas production for the second quarter was three million barrels of oil equivalent per day, 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 barrel, they more offset the natural field decline.

There were also negative impacts on asset 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 and it’s probably worth reflecting that the comparative figure against 2009 first half is 55% growth, showing what the portfolio can do. And that in this particular quarter it does reflect the successful ramp up of Qatar Gas 4 as well as higher volumes from Nigeria LNG.

Turning now to the downstream. The underlying downstream earnings were broadly similar to a year ago at $1.1 billion for the quarter. Lower results from oil products were partly offset by stronger figures from chemicals, our oil products earnings that were supported by very resilient marketing and trading earnings, and 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 year ago and these includes our 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 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 for the third quarter in 2010.

Our restructuring program in oil products continues with plans to improve our operating performance, take out $1 billion of cost, reduce our refining capacity and refocus our marketing portfolio. So those are the earnings and now turning 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 month has been $96 for Brent. Both the upstream and the downstream segments are generating surplus cash flow after investment.

We went through the cash position very carefully and I am pleased to say 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 improvement in 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 in our 0 to 30% range. Now, you would expect this in strong oil price conditions of course.

We made good progress on asset sales with some $4.4 billion of proceeds booked in the first half of this year and those combined with the ongoing asset sales means we are comfortably on track for the $5 billion divestment target that 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.

Our organic spending for the first half of the year is below the run rate we had planned for this year. First, it should accelerate in the second half following all of those recent FIDs that Peter mentioned. The second quarter acquisition figures include derived and joint venture but exclude the $400 million acquisition of UK retail sites that we have announced recently. We would expect to complete around the yearend.

So those are the comments on the quarter and with that Peter, I hand it over back to you.

Peter Voser

Yeah, thanks Simon. So 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 start-ups this year layout good foundations for financial performance in the quarters to come.

Investments such as Pearl, Prelude and Raizen are unique in our industry that are a great testament to our staff and our stakeholders and it reflects Shell's core strengths. Shell adds value through innovative technology, sustainable growth, integration across value chains and by creating long-life return for shareholders. This is a competitive and innovative strategy.

So with that, let’s take your questions. Now, please could we have just one or two each so that everyone has the opportunity to ask a question?

So operator, please pull for questions.

Question-and-Answer Session

Operator

Thank you. (Operator Instructions) Thank you for our question comes from Lucy Haskins from Barclays Capital. Please go ahead.

Lucy Haskins – Barclays Capital

Good afternoon. I'd like to ask on the integrated gas contribution to the quarter, it was very strong. Could you give some theory in terms of how much of that was coming from – we’ve seen good volume improvement, we’ve seen margin improvement, how much of the margin improvement was just the lag sort of oil price 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 and now you're building a path that offers more flexibility into your LNG portfolio?

Peter Voser

Yeah, thanks Lucy. I think I give this one to Simon.

Simon Henry

Thanks Peter. Thanks for the question. Very strong contribution indeed. It reflects, of course, our volumes are up very significantly, largely driven by Qatar and Nigeria, both of which have some optionality in them. So, proportionally, our ability to take the gas to a more attractive market has indeed increased. I wouldn’t necessarily call them arbitrage and implies that they are nonstructural. We are able to take the cargos in over quite a long periods of time, and particularly divert some of those volumes in from both plants that were initially targeted at the United States into more attractive market.

I don’t have a breakdown specifically from arbitrage price and volume because all of them actually interact almost by definition, and in fact the rapid start of the Qatar Gas proved particularly advantageous with more volume than we expected on which we were able to effectively take advantage. The number of diversions has roughly doubled year-on-year around 30 cargos, so pretty significant, and as you can imagine, primarily into Asia and the Middle East. So, strong performance, quite a bit is replicable. Of course, the arbitrage between Henry Hub and group-related pricing is particularly attractive at the moment; but I would highlight that in Europe the actual Spot LNG prices in Europe, the NBP was at least double Henry Hub typically trading $9 to $10. So, generally an attractive environment for LNG.

Lucy Haskins – Barclays Capital

Thank you

Peter Voser

Thanks Simon. Next question?

Operator

Our next question comes from Kim Fustier from Credit Suisse. Please go ahead.

Kim Fustier – Credit Suisse

Good afternoon gentlemen. Just a couple of questions please, firstly on Iraq. Could you please comment on the Basra gas deal that was initiated a couple of weeks ago, what are the next steps in here and when can you start to 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 assessed them for flow rates? Thank you.

Peter Voser

Thanks for the question. I take Iraq and then Simon can do China. Yes, we are very pleased of having signed the contracting on South Iraq gas. There is still more hurdles to go. I think the prime objective in the near term is clearly to capture flare gas and make it available domestically, and then over time as production ramps up obviously you would go into potential export scheme. So I would say they are a few years down the road and I think that planning would still take place a little bit later.

So I think we will concentrate first of getting the deal over the line, once we have it, then we will capture the gas and actually (inaudible) I’m sure we will talk soon about exporting gas then as well. We turn over to Simon on China Gas.

Simon Henry

Thanks Peter. China overall, just to reiterate the overall program there, we actually have of course the one operating concession Changbai. We have two large or one-type one-shale gas concession 4,000 square kilometer each in Sichuan Province and we have two CBM activities further north in Shanxi Province. So, 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 is great to be able to get up so quickly less than 12 months after we made the first agreements on the activity with our partners PetroChina. They are an excellent safety and reliability performance to-date through their – their contractors gives us great confidence of the joint venture that we’ve just announced.

Yes, we 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. So, our aim is to complete that what is truly an exploration program during this year, and define the next phase of appraisal for next year, but hopefully we would be able to lift the level of spending there next year. Okay.

Peter Voser

Okay. Thanks Simon and next question.

Operator

Thank you. Next question comes from Iain Reid. Please go ahead.

Iain Reid – Jefferies

Good afternoon gentleman. Couple of 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 and next year on the basis of your exploration and development program. And when do you think you are going to be able to recover the 50,000 barrels a day, which you’ve lost due to the moratorium?

Peter Voser

Okay. Thanks Iain. I think we have now – I’ll share this answer with Simon, I will give you a little bit bigger picture and then you can go into the barrels etc. We are very pleased with the programs we have made so far, albeit I have to say it's somewhat slow in the way they get permit so that needs to accelerate. We have -- the five fracs now operating again. So I would say from an operational point of view we are back to operating normally, but obviously we are still down in terms of barrels and Simon can take you through that.

So I think all in all pleased with the progress, could be faster and we are hoping obviously to develop things back to where we would like to be as we have outlined to you in your strategy presentation last year about earlier this year. So we are still in a catch up mode on that side. So to the barrels over to Simon.

Simon Henry

Thanks Peter. In total we currently received three exploration plans and development plan, couple of additional well permits. The exploration plans typically includes some drilling permits as well. We are or we said would 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 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. That’s down from 2010 and 2009. 2009 for last year pre-hurricane was 270,000. So, you can see quite an impact.

As we go forward, we expect to make up some of the gap. The comparisons against what we would have 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 Padido (ph) and ensure we are working over wells on the operating platform.

Now, 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.

Peter Voser

Thanks Iain.

Iain Reid - Jefferies

Thank you.

Operator

Thank you. Our next question comes from Jon Rigby. Please go ahead.

Jon Rigby – UBS

Yeah. Hi. A couple of questions. The first is on the mega projects you brought on this year. Obviously, the volumes are starting to come through, but if we upgrade for instance Athabasca we’re just starting up and presumably not all the products are being made in Pearl yet, even on the first train indeed. I guess you are still making them to put them into storage. Was there any real meaningful contribution from either of those two projects to earnings and cash flow in the second quarter? I am thinking is there actually quite a latent positivity on earning 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 just wondered how much of that was down to the U.S. business, and is there something sort of structural around profitability in the U.S. chemicals business that will stick around until – until U.S. gas prices close on some international prices. Thanks.

Peter Voser

Okay. Good. Thanks Jon for the two questions. Let me start with the first one. I’ll just repeat it. We had all the 70,000 barrels in from the three that includes Qatargas 4, which has ramped fully now and then the other two is coming into the quarter. Total capacity more than 400,000. So there is quite a bit to go in the quarters to come. Now, I give you kind of a summary of the three and the impact in the quarter. So rather Pearl, Qatargas 4 and AOSP, apart from the production we had roughly half a billion maybe 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 there was roughly a 100 million bucks in there from all of those.

Some we are still very late start after we are clearly negative on the cash side, because we are just building up the working capital. I think on the chemical side, I’m very pleased in how the chemicals business are turning 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 crack to actually being methane driven, has really made a big turnaround for us. We also have improved clearly the cost base, not just in United States but across the world.

So I think we are structurally better positioned now, and given the where the gas prices are etc. etc. I think you can expect a good performance and a strong continued 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 of wider view on this. As we said previously, we are also looking at how we can actually use the chemicals stream in linking that back to our tight gas and unconventional gas positions which we have in the United States. So we are also looking into that, how we can add further value further down the road. But I am talking about two years really down the road.

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

Jon Rigby – UBS

Right, thank you.

Operator

Our next question comes from Peter Hudson, please go ahead.

Peter Hudson

Two questions if I may. First one would be acquisition of the 30% of the Aberdeen floating LNG. Kind of check how that fits into the portfolio of other LNG profits you have got in Australia heading in the same direction. 2019, does that sort of jump up ahead of some of the years that you have got, for example likely to come ahead of arrow and does it use Shell generic technology.

The second one is on share buybacks, and I’m not arguing for aggressive share buybacks when you are making a very strong point about reinvestment for future growth. But the scrip dividend was to give balance sheet flexibility, and the balance sheet is extremely strong and I notice that you are not going into market to buy back the shares to cover the shares that people are not taking, they are taking a scrip, and you are expecting to be more aggressive in that i.e. the scrip dividend element should be neutral in the future and quite quickly.

Peter Voser

Okay. I think certainly the second one is for someone. Why don’t you start with number two?

Simon Henry

Thanks Peter. And thanks peter for the question. The dividend policy about the overall financial framework does indeed require us to buy back scrip or shares issued under the scrip program to offset the delusion 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 market but we will meet that commitment. There are no current plans to go beyond that commitment.

Peter Voser

Okay, Peter, then to your third question, I think first of all we are very pleased with our progress in Indonesia together with Inpex to buy into that LNG project. So very pleased about that and – they are the operator but I think we can bring some help and some advice and skills to that. We have - on your Australian question then, I think we are concentrating on Prelude as we have taken FID, this is our strong kind of focus. Now, as you know we have many – the other projects there like Sunrise, where we have already agreed with the partners that we will use our technology and also obviously working on Arrow where we have said that we will actually target LNG feed in 2011, and I think we are talking there around the first phase which should be two trains and eight million tons per year LNG.

Now we haven’t been forthcoming with exact dates of that further down the road and we will talk to you once we are further down and have taken FID etc.

So 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 into other areas.

Thank you.

Operator

Our next question comes from Mr. Griffith. Please go ahead.

Unidentified Analyst

Good afternoon. Just a couple of questions for you. The guidance you have given previously on cash flow from operations in $60 and $80 a barrel, you would like to see any change in that? And the second question was just from the capital employed at work at the moment, are you able to give an indication of what capital employed is now at work and where you might see normalizing it?

Peter Voser

Yeah, thanks for the question. On your first one, no, there is really no change to that. We’ve said in $60 and $80, where it's 50% up or I believe 80% up between ’09 and 2012. That really means that we are aiming at the $43 billion at the higher end and $36 billion on the other side if you take the lower amount. So no change to that. It’s also reflecting the production targets which we have given, which is 2.5 million barrels per day and this is what we are working for at the moment and then into 2012.

Around the capital employed, I give that to Simon.

Simon Henry

The capital employed just over $200 billion typically we have had over $60 billion of that not yet employed, still a work in progress or effectively signature bonus, acquisition premiums, etc. The coming on screen in Qatar and Canada we’ll have reduce 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 are effectively more productive but not yet producing (inaudible) exactly as Peter said earlier, the production we’ve only got 170 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 billion dollars in Athabasca at $70 a barrel. There is still quite a lot to come there.

Unidentified Analyst

Okay good thank you.

Operator

Thank you your next question comes from Brad Lucas, please go ahead.

Fred Lucas – JP Morgan

Hi it’s a Fred Lucas at JP Morgan, good afternoon guys. Couple of questions. Recently visited Rumaila in Basra Province Iraq, and there seems to be some confusion there as to what actual rights the Basra gas field might give you with respect to the gas that’s currently being fed by Rumaila which is very significant. I wonder if you could clarify that point. And the second question relates to LNG projects, especially with Prelude. I think now (inaudible) has indicated cost that around $350,000 a ton, which would point to total CapEx north of $12 billion dollars to recover just over half a billion 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 project methane to 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 and given emerging inflationary pressures in Australia more generally out stream?

Peter Voser

Okay. I think on the first one, I think we have heard the same kind of description from what you just more or less quoted. I think I will not go into that discussion at this stage. We have initialed a deal or signed one, which is now subject to two further approvals. I think once we are through that then we will inform what it exactly includes, and then I think it becomes clear to you as well. I think I leave the floating LNG to Simon, I deal basically 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 FIDs by others. That in our opinion will drive cost up and I think we are quite happy to go later into feed and then FID be already behind some of the others, because we think that gives us a cost advantage and as you know this is a joint venture with TMPC, which also gives us access to cheaper China sourcing. So 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 to divert other project in Australia at the same time. So, our annual spent mostly will be in the $3 billion to $4 billion in Australia alone over the years to come and I think let’s work carefully I will weigh into that. And then I pass on to financial performance on LNG to Simon.

Simon Henry

Thanks Peter. On floating LNG probably use 3.6 million ton per annum project, what we said Malcolm said was 3000 to 3500 ton of capacity. What we have not done is given any specific CapEx for this project. What we have indicated is that economics are similar to other large LNG projects, Greenfield ones in Western Australia, for example Gorgon (ph) or in fact the CBM project prior to the inflation that you just mentioned of course. The returns therefore are good, we will use this particular vessel to produce the Prelude field unlikely to other fields close by. Thereafter we will have probably a couple of decades of useful life left after which we will have already have gotten a very attractive return. Also, $20 a barrel I just pointed out isn’t such a bad cost in a relatively attractive physical environment and a $115 oil, it's pretty good at $70 as well. And so, overall we have to look at the commercial terms, the quality of the customer contracts to get the economics. And lastly I would say, yeah, the first one does cost a bit more, but you can be fairly sure of the second and the third and the fourth that would be a bit cheaper.

Fred Lucas – JP Morgan

Thanks. Could I just clarify on the Arrow project. You were saying that into an inflationary cycle that you committed on yourself is underway, the last of a four such projects could be cheaper than the first three.

Peter Voser

Yeah. I think once certain things come on stream 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 can always, we have got the possibility through our Chinese partners obviously the resource (inaudible) in a slightly different way, which will also help. We are building up this global wells JVVC and PC etc, etc. So I think we are doing all what we need to do in order to have an attractive profitable project there, which is rushed into 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 in and then ramp it up.

Fred Lucas – JP Morgan

Got you, thanks guys.

Peter Voser

Thank you. Next question please.

Operator

Thanks. The next question comes from Irene Himona, please go ahead with your question.

Irene Himona – Société Générale.

Good afternoon, this is Irene Himona from Société Générale. I have two questions please. First of all in OREO product, obviously a sizeable refining loss in Q2, is it possible to split the impacts to an earnings from low margins versus low volume for maintenance please? And my second question on cash flows, I think Simon mentioned the rolling four quarter $50 billion operating cash flow on an oil branch of 96 obviously 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, thank you.

Peter Voser

Yeah, thanks Irene. I think I give both to Simon.

Simon Henry

Thank you. The first one is fairly easy. Now, I can’t really give you a split between margins. The volume loss, $600 million was the overall loss, 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 divestment process, so it’s about 40 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, that’s the biggest swing factor. Another thing of course is we had said the 2012 targets expected I think a better refining environment than we have seen in the past 12 months and they were originally premised at $6 North American gas price, which is of course higher than today and you can take your own view of what that’s like next year. We are however committed to meeting the cash flow generation target next year.

Peter Voser

Yeah, thanks Simon. Having actually indirectly absorbed quite a bit of barrels which we have sold and still achieved a 3.5 million barrels also gives an additional challenge. But as Simon says, we are well on track to achieve it. Thanks Irene. Next question.

Operator

Thank you. Our next question comes from Lucas Hermann, please go ahead.

Lucas Hermann - Deutsche Bank

Good afternoon gentlemen. Guys 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 would say surprisingly large. That’s the first question. And secondly, I was wondering if you could just talk around North American gas production and the seeming lack of progress in terms of growth there, I’m not sure to what extend it's influenced by the divestment over the big (inaudible) Texas assets. But Canadian production doesn’t seem to be moving northeast or it’s just a gain, what’s actually happening in terms of drilling spent and intention at the present time relative to the targets that you set out in November last year?

Peter Voser

Okay. Now thanks Lucas. On the first one, we are really working on three key issues in downstream and therefore in manufacturing, which is really – the first one was portfolio, which we have got quite far down the road. We just announced another one a few days ago where we are switching the client refinery into a terminal. So that’s clearly making good progress and I think we are getting there.

The second one is about cost 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 one or two quarter project actually belong. And the third one is clearly it’s on the operating side, so actually constantly achieve our internal targets, which we have on up time, on utilization. So total capacity but also unplanned downtime.

I think the system has performed okay in some quarters, hasn’t performed in some others and that is part of our improvement program. If you ask me for this quote, did I leave money on the table, in some areas yes we did, and that’s part of our real focus on getting the manufacturing sites 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 advantage not being in the WTA area to benefit on that has also given us added advantage and one needs to take that into account. So I think I would say we are on track. There is more to come here and more to do.

Lucas Hermann - Deutsche Bank

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

Peter Voser

That is correct. That is what I am saying Lucas. Yes.

Lucas Hermann - Deutsche Bank

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

Peter Voser

Yeah. Clearly I’m investing for example in Pordarsar (ph) etc etc that is correct, yes. But we stick to what we have set as a target. Let me 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 rather than changing to account as well when you optimize your marching streams and your value to change streams. This comes into full flow when you start to actually cut your utilization rates of refining and once you would always look at that in an isolated way. I know it 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 steer our supply and trading and refining business like that. With that then over to North American gas I give that to Simon.

Simon Henry

The actual onshore gas volumes they are there, yes, from 1.2 to 1 bcf a day. That’s basically the reductions driven by the divestment in the South Texas volumes. The program this year is pretty much on track. Although we are in 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 Gramberge (ph) we are doing a fair bit of appraisal work in Marcellus and Eagle Foot. In both Gramberge (ph) and Haynesville there is quite a bit of drilling leaving gas behind pipe as we have not yet brought the infrastructure online. So drillings are on a bit ahead of the production in the year-to-date. So, we are overall still very much on track for that medium term target across the America’s. Building up and in fact a much better understanding of what is required to most economically developed Gramberge and Marcellus in particular because they are the big drivers.

Lucas Hermann - Deutsche Bank

Okay. Thanks a lot.

Peter Voser

Thanks Simon. Thanks Lucas and next question please.

Operator

Thank you and next question comes from Alejandro Demichelis. Please go ahead.

Alejandro Demichelis - Bank of America/Merrill Lynch

Yes. Good afternoon gentleman. A 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 ton (inaudible) 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 the growth profile of that business going forward?

Peter Voser

Okay. I take the second question and Simon will then deal with the first one. Raizen we have given you an indication of the EBITDA number, which we normally wouldn’t do and that because it's one part of one country’s business and it's rather small. But our partner has also published that on its website. I think I’m not going to go further into any gross projections on that. We will update on the gross of Raizen in our strategy presentations. I suggest you have a look at the website of our partner. You might find a little bit more there. And with that over to Simon.

Simon Henry

Thanks Peter. I’m not sure I fully understood the question, but I think if it’s about what’s the cost of a 50,000 barrel a day been? We stopped highlighting a (inaudible) on an identified cost on a quarterly basis. The actual full grown margin at the moment relatively easy to calculate. I should have calculated but it's 50,000 barrels a day, you are probably talking $40 a barrel plus or minus a bit in terms of potential earnings of $117 a barrel and that’s the opportunity cost and prior to last year the margin or the profit-loss was something over $200 million. So it is quite a significant reduction in our ongoing earnings potential.

Alejandro Demichelis - Bank of America/Merrill Lynch

Yeah. 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’s going into your P&L, isn’t it?

Simon Henry

It is relatively small there and we have actually got, basically the floating rigs are all back up and running.

Alejandro Demichelis - Bank of America/Merrill Lynch

Okay. That’s great. Thank you.

Peter Voser

Yeah. We have highlighted this in the past, but I don’t think it is that material at this stage any more.

Operator

Thank you and next question from Mark Gilman. Please go ahead.

Mark Gilman - The Benchmark Company

Guys, good afternoon. I had a couple of things. Simon, can you give me a rough idea of how you are entitlement over time is going to change on Pearl, assuming constant price?

Peter Voser

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

Mark Gilman - The Benchmark Company

Okay. The other is related to portfolio. I guess I’m a bit puzzled by the intent to go forward with a 10,000 barrel a day debottleneck at AOSP, seems very small and I guess I just don’t quite understand how the economic is going to be favorable on that. Similarly puzzled a little bit by the U.K. retail acquisition which at least in terms of per stations at about a 1.5 million a station, which seem to be expensive; little bit of color on both of those would be appreciated.

Peter Voser

Okay, good. I think Simon takes number one, I take number two.

Simon Henry

Thanks. 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 a $50 and $70. So basically we have quite a significant flow while we are in full cost recovery phase that takes about seven to eight years that’s at $70, obviously a lot less, if we were to say they are $117. There is then a step down.

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 seven to eight years before the first trigger at $70 a barrel, slightly longer $50, a lot less to $120.

Mark Gilman – The Benchmark Company

The two portfolio things…

Peter Voser

Let me start with the retail one, Mark. I think these are stations which are predominantly in the midland to southeast of England. They fits very well into our network which we have – we get to 1150 stations in total. We see great potential with our differentiated fuels and offering which you have and our lubricants offering. So I think these are all stations in prime markets, filling gaps which we have, and therefore does really fits well into the UK and deal with all the retail strategy on a global basis. And have met all the normal rather stringent profitability criterias which we have in downstream, specifically for marketing assets. So I’m pleased with the deal.

On the AOSP side, I think you need to look this in a wider sense. That we are going for development or debottlenecking of various, let’s say, tranches of the 30,000 to 40,000 barrels – 30,000 to 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. So, 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. We will do it in steps and they 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 debottlenecking.

So, I do agree that the number is rather small, but it make all the sense for future part of the de-bottlenecking that we built this one first.

Mark Gilman – The Benchmark Company

If I could just follow-up a little, do you have a cost number on either the tranches as you describe them or on the 10,000? And then just one other on Brazil; I guess I don’t quite understand the divestments that you’re undertaking in terms of Brazil. The intent to divest your 20% interest in BMS-8 follows on recent farm-down in one of your other Brazilian blocks. Talk to me a little bit about the strategy there with respect to your portfolio.

Peter Voser

Okay. The first one I think, 30K erected it will be around on the – the oil sands will be around $2 billion, (inaudible) which gives a breakeven below 50, and if you take some of the tranches within that package, say they will be quite below the 50, but on average, it will 50.

On the second one, this is an optimization of our overall global portfolio, including the Brazilian portfolio, and we are optimizing that and we will not keep everything in our pipeline. If you can do in summary farm down to get some cash contributions, et cetera. So, I think you should see 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. So I think 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.

Mark Gilman – The Benchmark Company

Thank guys.

Peter Voser

Thank Mark. Two questions more. Next question.

Operator

Thank you. Our next question comes from Oswald Clint. Please go ahead.

Oswald Clint – Sanford Bernstein

I guess the sort of net income or the earnings per barrel was a bit – was higher than I was expecting, also higher than your long-term trend relative to the commodity just for the upstream business. Is that primarily do you the LNG businesses, Nigeria – that Qatar volumes coming on that 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 Alumtia (ph) that you testing at this, wanted to know if you could give us any rationale behind that. Thank you.

Peter Voser

Yeah. I think Oswald you are right that the LNG volumes and strong performance there realize prices is in effect, there is a tax mix as well. If you think – we have been saying for some time beginning to start to come through. We’ve been shifting fundamentally the portfolio towards countries with more attractive fiscal regime. So once you start to get Australia, Canada, and Qatar and the United States contributing may be less from higher tax country such as Europe, you might see a better income per barrel going forward as well.

Peter Voser

I think the second question was that related to Sweden.

Oswald Clint – Sanford Bernstein

Yes. That’s right.

Peter Voser

I think the well results were rather mixed and we are not progressing I think will be the summary.

Oswald Clint – Sanford Bernstein

Okay. That’s great. Thank you.

Peter Voser

Thank you. Next question and last question.

Operator

Thank you. Our final question comes from Sergio Molisani. Please go ahead sir.

Sergio Molisani - UniCredit

Yes. Good afternoon to everybody. Two question on the potential gas re-export from North America. The first one is, can you give us an update on your re-export LNG project at the Prince Rupert in Canada in terms of authorization status and an investment at different time table and what are the main factors currently under scrutiny, which is pipeline’s location competition, contract agreement, and so on. And the second question is potential GPL in North America. You have highlighted in the past that the current oil gas price differential justify such decision. But what could make you actually and basically confident on the long term economics of these initiatives.

And the last question is that the Pearl GTL is a world class project. I suppose that the potential GTL in North America is likely to be a dry gas project. How this difference could affect the capita per barrel of the new project in North America compared to the $60 dollar per barrel we saw at Pearl GTL? Thank you very much.

Peter Voser

Yeah. Sergio, thanks for the three questions. I think they are 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 exposures or LNG exposures. So I think I most probably gave you a pretty – one answer to the three. 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 clearly on the LNG side, it is an export into the Asia market which gives you a different pricing exposure. Therefore, it is also for Canada differentiated in terms of not having only one market and close to them, which is DUS, it gives them a market opener somewhere else. So that’s one driver and I think we are progressing there, we 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 I think what you need is gas abundantly available, you need gas which has a reasonably low cash breakeven cost, and you need to have a big liquids market and I think in that sense the US obviously has all these elements and that could make GTL a possibility. Now, we are through Pearl, through our early investments in Tubintool (ph) in Malaysia, we are the company who is the best and the widest experienced in this field. So I want to say, we are 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 question. So, that brings the Q&A to an end today. Thank you very much for all your questions and joining us for the call.

We are hosting, some or most of you actually know, a shareholder engagement covering strategy and socially responsible investments in New York on the 9th of September and I hope that some of you will be able to join us in that event. So I look forward to seeing you there.

The third quarter results will be released on the 27th of October 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. Bye-bye.

Operator

Ladies and gentlemen, this concludes today’s Royal Dutch Shell Q2 results announcement call. Thank you for participating. You may now disconnect.

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