Ben van Beurden - CEO Simon Henry - CFO.

Theepan Jothilingam - Nomura Jon Rigby - UBS Oswald Clint - Bernstein Irene Himona - Societe Generale Fred Lucas - JPMorgan Lydia Rainforth - Barclays Capital Lucas Herrmann - Deutsche Bank Thomas Adolff - Credit Suisse Chris Copeland - Bank of America Merrill Lynch Jason Gammel - Jefferies Anish Kapadia - PPH Rob West - Redburn Bertrand Hodee - Raymond James Asit Sen - Cowen and Company.

Welcome to the Royal Dutch Shell quarter one results announcement call. There will be a presentation followed by a Q&A session. [Operator Instructions] I would like to introduce your host Mr. Simon Henry..

Thank you very much. And ladies and gentlemen welcome to today’s presentation. We announced first quarter results this morning. I will take you through them. Of course there will be plenty of time for questions and Ben will join us for the Q&A session.

Just before I kick off, an auspicious day today and not only do we have the BG acquisition in the background but it’s my 25th opportunity to discuss with you as the CFO the results and believe that over 100 times I have done this within Shell. So I look forward to appropriate treatment later. Before we start, let me highlight the disclaimer.

Only this month we announced a recommended offer to acquire BG. This is an important transaction for Shell. The combination with BG would accelerate our financial growth strategy, particularly in deep water and liquefied natural gas, both of these already growth priorities for Shell and areas where the company is one of the industry leaders today.

We’ve assessed this transaction on the range of parameters including the intrinsic value. This is a transaction which delivers value for both sets of shareholders across a range of oil prices. The transaction would be accretive to earnings per share and cash flow per share in a relatively short time scale.

It would have a strong complementary fit in the number of countries and this and plus the efficiencies that would come from joining the two companies together should lead to substantial value creation for shareholders over time.

All of this should also be a springboard for a higher rate of portfolio change, and Shell with an increase in asset sales, a reduction in the combined capital investments and reduction in the number of longer term portfolio themes. This should enhance our future dividend potential and of course the potential for share buybacks.

So it’s an exciting next step for both companies but let me just say that there is no change to the strategic, the top priorities set out for Shell a year ago by Ben. We are driving an improvement agenda today throughout the company.

This is all about getting to a more competitive financial performance, improving capital efficiency and ensuring that we continue with the strong project delivery. And the strategy is working and it is leading today to more competitive performance from Shell.

And this won’t change and it’s important we continue to drive that agenda in 2015 and beyond as we prepare to consolidate BG into Shell. Our current cost of supply earnings for the quarter at $3.2 billion, excluding the identified items, they were of course impacted by lower oil prices but some offset from our integrated business model.

Dividends were confirmed at $0.47 per share for the quarter and $1.88 per share for 2015. We’re continuing to curtail our capital investment, guidance today around $33 billion or less in 2015 and that is a reduction from what we announced three months ago of around $35 billion.

Although the market for asset sales is difficult we have made progress in the quarter, completing some divestments in Nigeria and making new announcements in oil products. And as I mentioned we have announced a recommend offer for BG which we expect to complete in early 2016.

Turning first to the macro for the quarter which has had quite some significant impact. Shell’s liquids and natural gas realizations declined substantially from the first quarter of 2014. Brent crude oil price is some $55 a barrel lower or around 50% than a year ago and similar declines in WTI and other markers.

The realized gas price is 27% lower than year ago levels with an even stronger decline in the gas prices in North America. On the downstream side, refining margins around the world were supported by lower crude and higher levels of industry planned than unplanned downtime particularly in the United States.

Industry base chemicals margins declined in Europe and North America as ethylene prices fell along with crude. However intermediate margins increased on the back of reduced feedstock and energy costs but also improved market conditions. And exchange rates moved sharply.

Compared to Q1 ’14, the US dollar strengthened against the euro and the Brazilian real by more than 20% and the Australian dollar around 14%. In the quarter, the average move on the small [ph], they’re still 8% and 4% respectively. This has quite a significant impact on our results. Now turning to those results.

Excluding identified items, our current cost of supply or CCS earnings were $3.3 billion, that’s a 56% decrease in earnings per share from the first quarter 2014. On a Q1 to Q1 basis, we saw significantly lower earnings in upstream but higher earnings in the downstream.

In the upstream, earnings obviously impacted by the significant fall in the oil and gas price but also lower trading contributions and exchange rate effects. In the downstream, results improved.

This reflected the higher industry margins but also the steps taken by Shell to improve financial performance such as from the divestment program and the underlying improved operating performance.

The return on average capital employed across the group was 8.4% excluding the identified items, and cash flow generated from operations was some $7 billion. Our dividend distributed for the first quarter of 2015 is the same as year ago levels at nearly $3 billion or $0.47 per share.

And we repurchased around $400 million of shares earlier in the first quarter. We have more recently of course halted that share buyback program to conserve cash in the lower oil price environment.

Our upstream earnings, excluding the identified items, for the first quarter were nearly $700 million, that’s a decrease of some $5 billion compared with Q1 of ’14. Now this figure includes $4.7 billion reduction just from the oil and gas price alone, a very large move.

And many of our LNG contracts are time-lined against oil by somewhere between three and six months. Therefore the first quarter of 2015, the LNG earnings do not yet fully reflect the drop in oil prices that we saw to date this year.

Now on a Q1 to Q1 basis, we also saw an $814 million reduction in earnings upstream total due to the increase in deferred tax balances as a result of the weakening Australian dollar and the Brazilian real. This was not taken as an identified item, but the negative 40 in the clean earnings.

These are very large movements which masked some positive effects from the growth barrels, from lower cost and lower exploration charges. The headline oil and gas production for the first quarter was 3.2 million barrels oil equivalent per day, excluding 190,000 barrels oil equivalent per today reduction from the asset sales and license expires.

While the overall volumes decreased, the underlying volumes increased by around 1%. Volumes are supported here by the ongoing ramp-up in deep-water fields in Nigeria, Malaysia, Gulf of Mexico. Maintenance impacts compared to last year increased.

This included Pearl gas to liquids stream 1 in Qatar which was in planned maintenance in the first quarter and production there at Pearl has recommenced during April.

In the Netherlands, Moerdijk gas field production was impacted by curtailment, the capacity curtailments requested by the government, by 105,000 barrel oil equivalent per day but this was fully offset in the quarter by the release of volume from underground storage but that is just a Q1 effect.

Now both effects are included in the performance category on this particular slide. Our LNG sales volumes in the quarter were almost 6.2 million tons, that’s up 1% year on year reflecting good operational performance but partly offset by the impact of the Woodside divestment in the same quarter last year. Turning now to the downstream.

The underlying earnings were $2.6 billion, 68% increase driven by higher oil products results, slightly lower chemicals. In oil products, we benefited from increased refining margins but also a much better operating performance. We have higher trading results, lower costs, some offset from lower contributions from marketing.

Chemical earnings were slightly lower than year ago levels but stronger intermediates offset the lower base chemical results. Refinery availability averaged some 95% in the first quarter, strong and improved performance compared with last year, in fact, probably our best ever.

The chemicals availability at 84% was lower than a year ago and that’s basically due to the downtime of Moerdijk in the Netherlands but that itself was improve from Q4 ‘14 levels as we continued to make progress with repairs there and the Moerdijk cracker is on track for a second half 2015 startup.

That should be earlier than expected and that with lower cost. Exchange rate impacts in the downstream are a mixture of positive and negative as they impact costs and margins but probably minimal overall impact to the downstream result. But overall this was a stronger quarter for the downstream.

Return on average capital on the clean CCS basis was 13.4 percentage points at quarter end. Downstream CFFO was around $10 billion over the last four quarters. Now just looking at costs, these are actual costs that we see as reported. There are cost reduction programs in place across Shell. They look not only to our own costs but also the supply chain.

It was good to see the progress on costs in the first quarter. The total operating costs as you will see them in the P&L, excluding identified items, fell by almost $1.1 billion in the quarter or a 10% year on year. About 65% of that movement is a result of stronger US dollar, exchange rate effects.

The remainder comes from our own actions to exit the non-core portfolio to cut back on our pre-FID options and ongoing cost reduction activities across the company. I remain convinced there is a lot more to come there as we drive down costs in 2015. Now moving on to the cash flow.

The cash generated from operations on a 12 months rolling basis was some $38 billion, that’s an average Brent price of $85 per barrel. Free cash flow, that’s cash generated less investments adjusted for M&A, was $2.7 billion in the quarter and nearly $22 billion over the last 12 months. Gearing at the end of the quarter was just over 12% or 12.4%.

The returns to shareholders, dividends declared plus the buybacks were $14.4 billion over the last 12 months. But just let me remind you of our financial priorities. We expect gearing to increase in 2016, particularly as we close the BG deal. We updated our financial priorities with the BG announcement few weeks ago. First priority remains debt paydown.

Secondly -- our growth asset sales and project growth, very important part of that. And secondly, dividends remain our main route to return cash to shareholders and then share buybacks have moved up in the priorities, will be assessed alongside capital investment, reinvestment in the business.

We did announce plans for at least $25 billion buyback in the 2017 through 2020 period assuming for successful completion of the BG acquisition, progress with the debt paydown and oil prices recovering towards the middle of the long-term planning range. Now we appreciate at this particular point in time modeling our results can be a challenge.

So to help me with this, this slide has some indications for the second quarter, also covered in the results announcement but you’ll also see an update on the sensitivities at the end of this presentation. I won’t talk to the slide but I would emphasize it does cover the foreign exchange currency effects.

Asset sales in the quarter, these totaled $2.2 billion. 2013 we set out the strategic view of the Nigeria onshore portfolio with an aim to reduce our onshore footprint particularly the oil and to refocus SPVC on to the gas value chains. Now we may have come quite a long way here. This is involved asset sales of some $4.8 billion in the last five years.

All in line with the federal government of Nigeria's aim of developing indigenous Nigerian companies in the country’s upstream oil and gas business. Recently we completed the sale of the oil mining license, OML24 and that was done at the end of 2014 – OML18 and 29 together with the Nembe Creek Trunk Line were completed in March this year.

Now together this marked very significant progress in the onshore asset sales program. Going forward, SPVC will continue to focus new investment on the associated gas opportunities. Now we’ve also continued to work on oil products divestments with the asset sales, including the MLP, master limited partnership. Last year they totaled around $4 billion.

Our recent enhancements in Q1 covered marketing positions in Denmark and the UK. Turning now to capital investment. We set out a program over a year ago to moderate our spending in 2014 with the reduction in both the headline and underlying organic spending, and we are continuing with that approach in 2015.

On the one hand, we need to make sure we have an affordable program and on the other, to maintain an attractive growth profile for our shareholders. I can’t update you today, we now expect spending this year 2015 at around $33 billion or less.

In other words, it’s about $2 billion reduction from the $5 billion ceiling on spending we set out three months ago. And we were very clear three months ago this is a dynamic picture. We don't make all our decisions on January 1. What you see now includes a series of pragmatic decisions on new opportunities.

For example, we pushed out the final investment decision on mezzanine to fulfil into 2017 or later.

We continued to reduce spending in resource plays and unconventional shale by around 20% this year and we’ve re-phased the development pace of Carmon Creek heavy oil in Canada phases 1 and 2 and we aim to optimize the design and re-tender some parts of that project to take costs out.

These steps come on top of the cancellation of our Guarani chemicals in Qatar and the other portfolio decisions that we made earlier this year.

Now we did curtail our spending anyway coming into 2015 to get down to that $35 billion level and we continue to review the appropriate spending levels in the company aiming to deliver that strategy and balancing growth and returns. Lastly just let me update you on the competitive position.

Clearly in the absence of a target, our actual performance on a competitive basis really matters. So you know we take a dashboard approach. We’re looking for a more competitive performance on a range of metrics over time not just single point outcomes.

We’ve been trending higher our return on capital employed and cash flow and last year we saw a significant uptick in the free cash flow. Clearly the oil price movements we’ve seen will push a number of these metrics downwards for at least the next few quarters. We have seen, though, that our competitive position is improving.

We will continue to focus on that. There is no complacency here. There remains still a lot we can do within our own limit. So with that, let me sum up. The results reflect the strength of our integrated business against the backdrop of lower prices.

Meanwhile in what is clearly a difficult industry environment, we continue to take steps to further improve the competitive performance, redoubling efforts to drive the sharper focus on the bottom line.

Looking ahead, post combination with BG should create a stronger company for both sets of shareholders and we’re looking forward to completing this transaction 2016. The priorities that we set out at the start of this year have not changed. The strategy is working today and is leading to a more competitive performance from Shell.

And all of this underlines our commitment to shareholder returns. Now with that, I’d like to move on to take questions. Please, could we have just one or two each, the usual request so everybody has the chance to ask a question.

Operator, please, could you poll for questions?.

[Operator Instructions] We will now take our first question from Theepan Jothilingam from Nomura International..

Hi Simon, hi Ben. Simon, I don’t know how to congratulate you on this quarterly result.

But just coming back to the capital investment that is in process and could you just talk about what further decisions you can make in 2015 that would reduce that $33 billion? And does the decision to make an offer for BG change your view on CapEx going forward? And the second question relates to the downstream and strong performance with earnings, but I see a working capital build in terms of on a cash flow basis, so could you just talk about how you see working capital particularly in the downstream evolve through 2015?.

Thanks Theepan. The capital investment – there are two sort of levels for these large decisions some of which I just mentioned and then the smaller project, the $500 million or less that’s essentially managed on the portfolio basis, we are aiming overall to the two things. One, just take costs out in the supply chain.

A lot of that activity refers to divisions or investment decisions not yet taken. So while we may get cost reductions they may not impact hugely in the current year except on some of that small projects. And so the other area is really deferring capital where that can be done without losing value.

I think that balance that we’ve taken so far shows you we’re taking a fairly well considered approach to that, working within our means. There are one or two large decision still coming up, the first couple I guess are the Appomattox investment, deepwater very large project decision middle of this year.

We also have other investment decisions on Vito and Bonga Southwest and Libra in Brazil, Vito is also Gulf of Mexico, those are four big deepwater decisions. LNG Canada and chemicals plants in Pennsylvania are probably the other large decisions in the next 12 months.

In all of them we are looking at what’s the right timing and what is the right cost base to go forward with.

In total there are around 17 final investment decisions in ’15 and ‘16 and we’re not thinking about just the one year of CapEx, we’re looking at essentially the next 3 to 4 years where we are well aware that we need even without BG to be retaining some as much flexibility and strength on the balance sheet as we can.

No, BG doesn’t change our view on CapEx, for 2015 not really, we do what we can do. Our options are relatively limited. Going forward what we did say is that we’d expect even in ‘16 that the total investment should be less than the simple pro forma addition, i.e. to add up to less than 40.

Going forward, difficult to say anything more than that, at this point in time but clearly richer portfolio, set of options hopefully we can make sure we get a good balance of choices. Downstream capital build, main reason it’s come back a bit in Q1 is the price increase by the end of the quarter.

So we are heading up towards 60 and so that will continue as long as the price increases, the working capital will increase. If the question is partly about trading working cap, yes, we did give them an open credit line probably about 8, 9 months ago now which they've utilized up to $2 billion from time to time.

I can't give you what they were at any given point in time but that’s the level of working cap they’ve been using. In addition, additional regulatory requirements in terms of putting transactions over the exchanges is chewing up capital over time.

I don't have a figure for that but we’ve previously spoken about $1 billion to $2 billion because of additional and in our view, not only unnecessary capital requirements but ones which increase the total risk in the market and decrease the liquidity and the ability to match with flow for our customers.

So it’s worrying regulatory developments which are not helpful but the primary factor at the moment is the increase in the oil price..

Thank you. We will now take the next question from Jon Rigby from UBS..

Hi Simon, I have to say I think you’re starting to get the hang of it slowly, the quarterly, so keep the good work up.

On the questions that I have, the first was, one of your competitors indicated that a likely delta to reflect the very strong trading conditions of sort of $400 million, $500 million, would that be a sensible number to think about in the context of what Royal Dutch Shell was able to do just in the oil trading side, I understand the cash trading was not as good this quarter? The second thing is just on CapEx itself.

You referenced that you had the option to defer spending. You clearly have the ability to go back to suppliers and discuss lower pricing, lower invoicing. But there is a third element to this, I think which probably goes to the real problem the industry has which is just how you go about doing stuff.

And so do you think over the next 2 to 3 years we will actually start to see something fairly material resulting from the reviews and the re-examination of how you go about doing projects scoping them out and then executing them?.

Thanks, Jon. I think you may be close to a century actually, so thanks for the comments. The changes in trading and maybe I will ask Ben to comment on changes in projects. But trading – remember, our trading business essentially is adding value to molecules that are flowing through the system, that fuels value chain in practice.

We produce 1.5 billion barrels a day, we refine three and we sell six. So we doubled – we refine twice what we produce and we sell twice what we refine. And trading is basically the glue in the activity that enables us to do this in the most optimal way.

Two years ago, Ben changed some of the organization accountability, the way we think about managing that value chain. Building on some what we've been doing including systems development and that transparency change and accountability has in practice helped us add more value certainly to optimize the value in our downstream business.

We talked last year about that plus cost reductions adding maybe $1 billion pretax to the earnings performance. We are continuing to deliver that. So trading is not a separate activity, it is embedded in adding value to molecules moving to customers.

Yes, the desks do operate 24x7 and they are operating some positions with quite a limited value at risk but it will be wrong to characterize the activity as standalone or separate from the day job of meeting customer requirements. We did earn more on the oil products and crude trading side.

But it's only on the order of a few hundred million and it’s almost impossible to extract that from the pure refining results as well, which also had one of our best quarters, partly in at least because they operated extremely well in the quarter. I can’t say too much more than that.

I am afraid that, other than that the improvements made are structural and will last for some time.

It’s an excellent question about the -- will we see structural changes in the way that companies operate together, particularly on the project side, everything from scoping through design but there also may be in complexity that we sometimes add but Ben probably, it’s a good one for you to pick up. This is about competitive edges. .

Thanks, Simon. Yes, thanks, Jon, very good question. You have to be right, it’s at the moment it's all about making sure that we get the projects right in terms of timing and decision-making.

So it’s very very much challenging, can we afford to take this on but also if you take it on, is the cost competitive in the environment within which we make the decision, if not, then, we have to find a way to work harder on that and by and large, indeed, you can of course be scoped to some extent.

But if you assume that you didn't get the concept wrong to start off with, it is basically trying to – either we’ve done, or get a more competitive deal. Now fundamentally, you have to be right, a lot of the escalation that we’ve seen is somewhat more fundamental and structural and we need to get a handle on that as well.

I have made it very very clear with our project organization and had very good months, there is no doubt, getting projects to be absolutely competitive in the industry and more generally getting our development portfolio more competitive, I think it's a long-term license to operate issue. I don't think you can see it in any other way.

Now what are the things that we can do? First of all, have better teams in it, have better practices, better approaches, better scoping, less re-working, better upfront decision-making, front-end loading, all the sort of things that we have been doing for the last 10 years which basically has moved us by and large into the first to second-quartile depending on what types of projects you look at.

So I think we are probably sort of getting at the point where we understand how to do that well. But that clearly isn't good enough either. We have to now think and there is the right time for it.

Can we, indeed, take complexity out of the projects? Can we have a more standardized approach to projects? Because if you look at how project has evolved over time, they are just taking up much more time, much more efforts, they take longer to build and some of it is the result of less experience in the industry, more overheating in general, probably also the result of higher and more difficult requirements that regulators and other and society maybe in general puts on us but some of it is probably also sophistication that perhaps we didn't quite need as much.

So simplifying standardizing is another approach to take and with it, actually very closely related to it.

You can think of how do I transform the entire supply chain? So this is not going back and renegotiating contracts but actually working differently with core suppliers, be it technology suppliers, equipment suppliers working much more with standardized solutions, long-term solutions, replication of designs, ordering multiple items of the same thing at the same time because you know you're going to use it going forward in multiple projects.

And these are sort of things that we have been working on as well. We are making progress in the sense that we have good enterprise frame agreements, that we have strategic relationships, that we have investment themes like deepwater, like integrated gas that we take sort of multiple project views on things.

But there is more to be done, Jon, and I think yes, you will see leading companies, and I like to think ourselves being amongst those, taking a different approach to projects going forward along those lines..

Thank you. And the next question is from Oswald Clint from Bernstein..

Maybe can I ask a question about the European gas business and kind of related to the NAM volume obtained in the second quarter which is a decent chunk of the volumes.

Does this, especially in terms of not being able to store gas, does this pose any kind of customer delivery gas contract issues for the second half of the year, certainly through winter? And ultimately if you could just talk about the NAM being potentially shut in for longer or is it an opportunity whereby pricing could strengthen and you could actually sell forward some natural gas into the winter months? That’s the first question.

And then secondly, I was just curious about going back to BG, I can’t remember the slides back on the day, it is $2.5 billion worth of synergies plus some further upside potential and I think, Simon, you’re a bit – I think the wording, your comments was much more about substantial value creation this morning.

So I just wondered it’s out of change in kind of wording over the last month, is kind of how to better look at this, is there more scope or like kind of value creation side?.

Thanks, Oswald. I will take both of them. The gas business, no supply issues at the moment. Groningen has historically acted as the gas central bank for Europe in terms of demand being driven by weather. It's actually been a pretty warm year so far as you’re probably well aware and no supply issues at all.

As we go forward to next winter, while cold winter could obviously put pressures on, the gas storage underground can be filled from sources other than Groningen and I would expect there are many more sources than just Groningen that can help prepare. So we don't know actually what the government will request as we go forward.

The actual levels have changed a couple of times already but we’re not expecting significant impact on pricing. On BG, the $2.5 billion sale synergies were externally verified, audited, then subject to regulatory reporting rules, therefore they are real but about as far as we can go.

And it’s only three weeks since we announced, of course, it seems longer in many ways. So, we’ve not done a lot to change that detailed view and it’s unlikely that we will for some time. What the substantial value refers to is what I might call all the more difficult to identify value synergies. So the $2.5 billion is reduction in spend auditable.

The real value comes from what can you create, for example, by bringing the two LNG portfolios together from the deepwater expertise technology operational that we can bring, for example, to Brazil.

And in general as the BG portfolio matures more into development and production assets, that’s perhaps more an area of strength for Shell than it was for BG, which built great value around exploration and LNG market development.

So some complementary skills but obviously value opportunity, while we see it we cannot claim it until the combination is in place and we are delivering it to the bottom line..

Thank you. The next question is from Irene Himona from Societe Generale..

I had two quick questions. So firstly on OpEx. You mentioned, Simon, that you had $1.1 billion reduction in costs in the quarter of which 35% is self-help, so that’s 385 million out of 45 billion I believe cost base for Shell.

My question is how sustainable is the 65% which was FX related and I know you don't communicate external targets but any comments would be much appreciated. And secondly, I just wanted to ask if you can provide some visibility perhaps on the components of the Upstream Americas loss this quarter.

It lost over $1 billion, Canada is half of the production.

Can you give some insight on the different bits of it such as unconventional, oil sands et cetera?.

Sure. Irene, thanks. The 1.1 is a year-on-year ago figure, so that is always a bit of seasonality in there as well. In general if the currency rates stay where they are, we’d expect maybe a couple of billion dollar reduction year-on-year because they did move during last year.

I hesitate to bring my neck out too far but we ought to be seeing not entirely dissimilar numbers from self help as well but it will be offset as new projects do ramp up and create their own costs as well. So very focused within the company on delivering those numbers and we will update you on a quarter by quarter basis.

We will say – to take the costs out forever as well, not just temporarily. And Upstream Americas loss of a billion is -- you know businesses, deepwater heavy oil, unconventionals plus that of exploration. Deepwater and heavy oil, absent the Brazilian currency movement were about breakeven.

Brazilian currency movement 300 plus Alaska exploration spend plus roughly similar numbers, this actually is about a third each. The ongoing loss in the unconventionals contribute to the $1 billion loss overall.

In practice, the unconventionals is a much better place than it was a year ago, the challenge is the 250 Henry Hub gas price and realized liquids prices well south of 50, given the nature of the market within North America. Now I think it’s fair to say that everybody is showing either a loss in the Americas or very close.

We may have what is apparently the biggest loss but these reflect that 300 million is Brazilian currency and a similar number for the spend so far in Alaska. .

Thank you. The next question is from Fred Lucas from JPMorgan..

A question around impairments and provisions. On provisions, can you remind us what provisions have been taken by NAM related to the compensation [ph] issue there and what you have over those existing provisions, how much of the provisions have been consumed? And on impairments, again you haven't taken any significant impairments.

We’ve seen today Statoil take a very substantial impairment which I think as explained by them is a change in their medium-term prospect.

So on the same subject matter, could you remind us how you calculate, or how you do your impairment estimate at what point you overlay your medium-term price beyond the curve and perhaps also indicate if you were just to use the curve, as far as it can be seen out to 2022, whether you will still be safe from those impairments or whether the absence of the impairments relies upon that recovery to the midpoint of your 70, 110 pricing, so question is really around provisions and impairments please..

Thanks. But to the NAM provision first. And I can’t remind you because – it’s not major at the moment but we're looking always very closely at the developments in terms of our compensation can and should be calculated. You may be right of the parliamentary debate this week in the Netherlands. At the moment there is very little impact in the results.

The biggest impact has been the reduced production. On impairment policy generally, we basically look at forward cash flows using the midpoint of the 70 through 110 range, so we take long-term 90.

We test not only short-term with a lower price as well but from time to time when we did some of this in Q4 with a flatter or lower price at the bottom end of that range. The assets that are closest to impairments – you very kindly say we haven’t taken impairments.

I think we have in the past, particularly in shale unconventional, shale unconventional activity in the U.S. both taken impairments but also divested quite significant parts of the portfolio.

We have said that there remained a couple of assets there Grand Butch [ph] and Appalachia or the Marcellus that were we to take a different view on gas prices, not oil but gas, we could come with a different outcome there, or if we decided not to proceed with LNG Canada, that’s where the gas from Grand Butch is ultimately targeted.

Elsewhere in the portfolio there is not that much that is close to the edge and we’ve had discussions previously about Kashagan and that’s really a question of when does it come up and running, it’s a strong cash generator once it does. Until that point it would be vulnerable to a change I am sure in oil price assumption.

But overall the portfolio remains fairly robust against lower oil price expectations. We’ve not run the forward curve out to 2022 basically because that’s not what we perceive the prices should be and nor necessarily that should be the basis for impairment. Hopefully that helps and that’s not a change in policy, that’s basically ongoing policy..

The next question is from Lydia Rainforth from Barclays. .

Two quick questions and then one for Ben if that’s okay. On the cost base and the chart that you showed indexing costs past 2011.

Was there a particular reason that you chose 2011, is that the sort of scale of opportunity that you are thinking of or was that just the opportunity greater than that? And then just very quickly, can you remind us how much the investment in Arrow has been to date? And then just finally for Ben, can you just talk through the reaction that you have seen from stakeholders, the governments, and other operators, post the announcement of BG deal?.

Thanks Lydia and nothing is finished during the selection of 2011, it’s just to go back several years.

On the gas it’s posed, we had a bit of a wobble in the cost base between ’09, ’10 if you remember cost on oil prices dropped a bit and so ’11 – so the first year of the $100 run and so also of course excludes the Macondo year as a baseline when quite a bit of impact on individual companies.

The investment in Arrow, I am not sure if we have given this before but it was several billion dollars upfront obviously to enter, we then divested them 50% to PetroChina and we have ongoing activity but in terms of Shell investment several hundred million per year rather than billions.

Clearly Arrow is in a position where -- we need to think about the best way forward to monetize and to create value from the position we have and now there is an additional element which we can’t continue yet until we are at the point of closing the deal.

But depending how we monetize I cannot -- should not rule out any impairment on the carrying value of Arrow. But it will depend on how we choose to develop which in itself could over time depend on the combination with BG..

Well, we of course had an interim update with some of you earlier on. Let me just say that by and large going around the markets it’s fair to say that the logic of course is very well understood. It’s everybody thinks it's compelling, it’s logical to do this, it makes sense.

I think there was in the beginning of course quite a bit of discussion to what extent – at what oil price does this work, I think that is beginning to settle as well. People see it works in a wider range of oil prices.

I think there is a little bit and I'm sure you yourself will be running to the middle of that, a little bit of the molding, sort of effecting going on to understand the numbers that we have given out but by and large I think that is starting to converge and settle as well.

And I think what I have heard in the mix if I add it all up, I believe the consideration, the way the offer has been structured, and the way we have approached valuation is being seen as sensible and fair for both sets of shareholders.

In the meantime I've been speaking to key stakeholders in the business as well, been to Trinidad and Tobago which was a very positive and good meeting, met with the prime minister there who was very much welcoming of course of the development. If the transaction goes through we will of course be the largest integrated player in the country.

So it will be important for them to understand where we come from and I think we have very very good understanding of what we like to achieve, what our long-term view is in the country and assets et cetera. Brazil, similar if not even more positive meeting with the president.

President was very positive, meeting with Petrobras was very positive, meeting with the energy minister was very positive. Next week it will be Kazakhstan and China. Let’s see what will come out of that. I think what we of course hear is again positive and logical and likewise we have good and positive reception and messages coming out of Australia.

So it's of course incredibly early days. We are – as you can imagine, right in the middle of getting all the applications filed for the regulatory approvals. I think at some point in time we will probably need to give a formal update but at this point in time it’s not – it would be premature but I think so far so good but early days. .

The next question is from Lucas Herrmann from Deutsche Bank..

Two relatively straightforward, I think, Simon, CapEx.

I just wondered if you could talk about what you’re actually seeing in the market across the different service sectors in terms of pricing as you go and discuss? And secondly, I just wanted to go back to OpEx and just walk through – I am getting rather confused, apologies, in the context of the savings you hope you will be able to achieve on operating costs, I guess almost around the time that Ben started to push for change more aggressively, or for efficiency more aggressively at the start of last year.

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What are we seeing in the market? Well a variety of reactions. We can take a standard response to asking for reductions on the costs.

I think Ben captures it pretty well ultimately around the capital investment in totality is as much about design and scoping and then efficient management to the supply chain, that’s moving out the demand profile, it is about the unit price. It’s also about working in a collaborative way with various different elements of the supply chain.

In some places yes, you can take costs out. You can see they are happening in places like the North Sea. You can see they are happening with the rigs both onshore and offshore, particularly on the short term offshore rate.

It’s not happening as much and the more oligopolistic path to the business, the subsea equipment for example, but there are some good discussions ongoing that may basically, as Ben said, lead to much longer more structural and more constructive cost take out for everybody.

And it’s quite difficult to say more than that without getting lost in the weeds, Lucas. We do expect though that over time CapEx, the unit cost level in aggregate trends in line with the oil price. So the two are not independent metrics.

And on the OpEx, I will try again but the baselines do differ but let’s take 45 as a baseline number, was last year’s OpEx and it’s where -- roughly where we have been. Now we’re all seeing a 5% reduction in that from foreign-exchange like for like and that would flow through this year if FX rates don’t change.

We are targeting at the micro level – a big hairy goal at the corporate level of x billion dollars but within the business, within a function, within a geography, within a business we talked about unconventionals for example that they together with the Upstream Americas team, they know they need to take a $1 billion plus out of their cost base.

Some of that is overhead, some of that is at the frontline in terms of the drilling activities, some of that comes into CapEx, some of that comes into OpEx. We have – the downstream, John has talked about $10 billion of cash flow from ops and 10% return on capital across the bottom of the cycle.

He has cost targets embedded in that and in each part o f this business, whether it’s manufacturing or marketing.

We are currently looking at the international upstream business as to the total level of cost in that business as to where that should go particularly in areas where maintenance costs have been increasing over time inexorably and think of the North Sea.

And lastly the functions I personally have targets of around $1 billion in the finance and IT area from the spend we were at a year or so ago. Internally my other functional colleagues in legal and human resources. So we’re talking some nontrivial numbers by the time these all add up.

But there is not big hairy goal either internally or externally for a very good reason.

We do not want to divert the entire organization from creating and adding value through a multiplicity of value levers, including costs and then switch them on to just the single thing because if you cut costs too much and with too much gusto today, you almost always regret it tomorrow. And I can give you that but probably no more.

The direction is clear, it’s going in the right direction. Ben, is there anything you would add to that, because it’s much about the leadership psychology as it is about the numbers..

Yes, thanks, Simon. Thanks, Lucas. It is -- I think of course it’s incredibly topical at the moment and it's of course very very tempting to put all sort of high level big hairy cost bag that’s out there to show that the organization is responsive. I think in the end as Simon says, it quite often also leads to the wrong behavior and wrong outcome.

It’s just going around the organization and say give me, what you can do or maybe even more stupid, I will tell you what you should do and then see whether we can deliver against it, never really gives anything which is either sustainable and most likely also not targeted enough.

So you have to – and that’s the philosophy that we have adopted, you have to go deeper down into the weeds to understand where costs can be taken out, and it’s either because you look at efficiencies and functions, you look at efficiencies and IT systems et cetera, or you look into individual pieces of business often down to the performance unit level, where you just say, either first of all, how is my cost base and how can I benchmark this to see whether it’s competitive or not and quite often you can already find, therefore, the inefficiencies in a very targeted way why would my maintenance spend be 3 times higher or even 20% higher than what is first quartile in the industry and trying to think that through and maybe there is a good reason for it but maybe also not.

And that will get you much more precise focus on where to raise this.

You can also take a slightly different approach as we often do in performance and doing the test [ph] and if you want to have this as a competitive business, what sort of cost levels could you afford and how could I get to that cost level? And if you can’t get a way to that cost level, maybe the business is fundamentally weak, you better get out of that business.

Or maybe you have to think of the business model or how you create margin in that business or whatever it is but you have to have that type of approach.

So cost related to value creation and specifically targeted on an understanding of how the operation is doing, if you want to make the right sort of decisions that are sustainable and do not end up in regrets later on.

Now as Simon says, we have hundreds and maybe even thousands of target points throughout the company where people work along these lines on what are the right things, with many many metrics on, what is my return on this piece of OpEx, what sort of utilization do I get out of that piece of work et cetera? Now we don’t add it up and we don't put a bow around it and we don't say always x billion and you’re going to measure us against that, because again that would fundamentally go against the grain and philosophy on how you manage for performance.

And I know that other companies do that. The way with we wanted to approach at this time around is look at what we deliver. Yes, this is not about where I'm going to get to quarter on quarter, this is basically how our performance looks like, in terms of value delivery and of course you look at – it cuts out of the costs as well.

So you can see how we're doing in terms of OpEx delivery. I think that should be a better way of judging whether we have the right approach to this..

And the next question is from Thomas Adolff from Credit Suisse..

Two questions please. The first one, I just wanted to go back to Jon Rigby’s question. Yes, indeed the industry can improve and IKIA [ph] has good statistics on that and you talked about simplify and standardize approach to take complexity out. But even with the old approach and if I look at Exxon, they’re so way ahead of everyone else.

So I wondered whether there’s simply a bit knowledge gap or whether the industry has just been complacent because the oil price was at $100? Second question, I guess is just on the capital intensity of the business. I think most companies, the most of your peers would say portfolio decline is around 3% to 4% of the sum spend.

If I look at the business pre and post BG deal, obviously you have some long life assets coming on stream over the next few years but given that BG overall has a business is relatively more long life, even to Brazil stuff, how should I think about portfolio decline as a combined entity?.

Let me talk to the first point. Yes, it's probably true that companies like Exxon are way ahead of everyone. They are very – they are working in the same league as we are. So I would like to push back to the idea that anybody else's ahead of us when it comes to taking costs out to understanding how you do projects well.

We have been on this journey to improve the way we do projects since 2004. We have very very clearly for all major projects squarely benchmarked in the first quintile, this is done is quintiles. Indeed quite often together with Exxon, or ahead of Exxon. So just if you do not buy that, just look at their reports, it will be very very clear.

Maybe we should bring that back at some point in time as a proof point as well in one of our presentations. So yes, this is complex, this a difficult but again I do believe we are on track and there are many examples to make that points. If I just go back to this year, look at what we have done with Mars basin.

Yes it is very very clearly an example where – if we know how to manage the stuff, we will deliver outstanding performance.

We have unfortunately also the ability to benchmark an awful lot within our portfolio, if you look at non-operated assets and also there you can see that systematically if not without exception we are ahead in terms of performance in our operated portfolio compared to a non-operated portfolio.

So there is a bit of benchmarking that we have in house as well..

Thanks, Ben. Capital intensity, it’s a complex question. So I will try and be as quick and simple as possible. There are portfolio effects in any overall measurement. So clearly decline rates are different whether it’s conventional, LNG stroke, heavy oil or shale, arguably you need to separate them out.

But overall our portfolio has been running more like three percentage points decline year on year. That’s what we saw Q1 versus Q1. And that assumes some level of infill drilling and pressure maintenance et cetera.

As we go forward, we’ve not just through BG but through the choices we make ourselves to upgrade, it is likely that we will be focusing on, if not, zero decline which is a less material assets.

So our exposure to high decline and high cost of maintaining production assets is likely to decline overall and give us a portfolio not only with a longer life ahead of it but one with lower capital maintenance requirements. But that is difficult to say any more than that without getting quite granular.

Yes, the direction is correct, gas plus big deepwater offshore where you continue to have to drill but typically the aim is to keep the facility full such as the FPSOs in Brazil or in Nigeria or the TLBs in the Gulf and that's what the choice is, the big investment choices will be a target to that ensuring we have assets that while we need to drill to keep in full there is enough resource to doing that in that.

If we were to look – it’s worth also saying look at the dollar per barrel metrics, they are also highly driven by the portfolio.

I don’t mind the higher dollar per barrel investment, if in fact the margins available justify it and that’s very much a measure of the fiscal regimes we choose to invest in and we strategically made quite large shift in our portfolio some years ago to what we felt are more attractive fiscal regimes and you can see some of that coming through in our earnings and cash flow per barrel now and what our in effect lower tax rate in the upstream.

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And the next question is from Christopher Copeland from Bank of America..

I'm not really sure what I am about to ask questions given the restriction that the recent M&A activities put on me. But I will try anyway very briefly.

The sensitivities at the back end of your slide pack, would I be right in assuming that you are referencing this very much in a year-on-year context, rather than a quarter on quarter? Because if I apply the Brent and Henry Hub sensitivities you have given us to first quarter ’14 which I remember was a very strong quarter to first quarter ‘15 and obviously adjust for the FX effects.

This looks to me like it's been a very strong quarter in ’15 again. Would that reflect the earlier gas price lag that you mentioned? Sorry for a very long question, probably only has a very short answer. And second question is purely only the refining margin outlook.

What are you seeing at the customer end in terms of demand growth coming through or not and what do you expect directionally for the rest of the year?.

Thanks Chris. I think as long as the Chinese rule is in place, you are welcome to ask anything you wish. And the sensivities – in simple terms you are right, it was a good quarter for the upstream, operationally weak as well. The other thing is our production was impacted by more turnaround on high value activities in the Gulf and in Qatar.

So actually in terms of the actual performance of both upstream and downstream, we were quite pleased with what we were able to achieve. We continue to improve safety statistics as well and unfortunately in the $55 oil, it doesn’t all show through. So whilst generally a good quarter and refinery margins, they have started to come up anyway.

They were helped by demand in North America, that certainly US demand is pretty stronger than we might have expected, coming back a bit. Cheap gasoline is always a bit of a boost to in the economy and in developing markets, it’s less clear and there is demand growth coming back.

Last year it was just below million barrels a day growth, we would expect somewhere between 1 million and 1.5 million barrels per day growth in any given year and this year so far looks like it will fall in that range but it’s a little early to say is this going to be enough to close the supply demand gap? In and of itself, the answer is no.

Because the supply overhang is potentially quite a bit higher for some time to come. But over time yes it will. And just on the basing the FX impacts, for any given quarter, so we see the Australian dollar move by $0.05.

During a quarter you should see roughly a $300 million earnings impact after-tax included in the earnings, clean earnings and similarly for the Brazilian real, of course that’s a much lower sensitivity. .

And the next question is from Jason Gammel from Jefferies..

Just to square a couple of comments you made over the course of the call, Simon.

Related to the deepwater FIDs you would potentially take midyear to before the end of the year and entrusting that with the idea that you haven’t really seen much in terms of savings on very specific deepwater items but I would think deepwater in general other than rig rates, what’s the advantage in moving forward with those FIDs this year rather than waiting and seeing what happens from a deflation standpoint? And then just within the context of that question, are you able to move forward with the Bonga Southwest FID given the uncertain status of the PIB in Nigeria?.

Good questions, important though. Basically there is four big, big decisions, Appomattox, Vito, Bonga and Libra. At one point all four of them could have been 2015 decisions. Libra is just the first FPSO of course and Appomattox has license conditions where we do need to reach a decision on how to develop during 2015.

The good news is it’s a very significant discovery, 70, 100 million barrels, 80%. It’s a new play. It’s got still further exploration potential around it. So in resource terms and potential value it is the right one to be first.

We went into feed just about a year ago and there has been a significant focus enough process on taking costs out, particularly around the drilling program which is very close to half of the total spend and that comes up for decision in a few months time.

Vito, we are exploring around it, we’ve had success and it may end up being bigger than we expected. Great opportunity to do precisely what you said although our original intent was to make the most of two projects and take synergies from the standardization and the bulk buy opportunity, two for the price of one.

Bonga Southwest, we have been out to tender.

We don’t like the costs, on some of those – the responses we’ve had, and also there are ultimately quite a few moving parts one of which will be re-tendering some of elements of the project and the government, there has been election, we’re pleased to see the peaceful handover of power but the government hasn’t -- the new government hasn’t actually taken their seats until the end of May and this project has many partners.

We will be the operator but it includes almost all our large competitors. So there are some complexities and getting everybody to support a project. I can’t say anything about the PIB. We will look for some stability in the fiscal framework if we’re going to take a decision of this magnitude.

Not obviously we will need the new government to play their part as well. So in practice that decision is moving backwards. In Libra, we are going ahead the original plan.

Obviously there is new Petrobras management in place but that plan was to look to place the order for the first FPSO, take the investment decision but by the end of this year give or take, that’s still the expectation, that’s very much in the hands of Petrobras which as you probably realize on the new management.

So now it could be some movement there. All of these projects other than Appo, will benefit from the suggestion that you make as to just buy your time and take the costs at the right point in the cycle. Appomattox is probably the most attractive project amongst them anyway. Hopefully that gives the perspective..

And the next question is from Anish Kapadia from PPH..

Couple questions from me.

On the BG deal going back to that, it sounds like you see completion risk is relatively low and if this is the case, so I was just wondering given BG shares are trading at 11% discount to fair value, one would buy the BG shares in the market or are you waiting to kind of get more certainty on the deal? And then the second question is, just more generally on Nigeria, you had a pretty significant change in regime over there.

Just wondering how that is expected to impact various things such as the onshore asset sale process, some of the gas projects you’ve got in place and future investment decisions in Nigeria?.

Thanks Anish. I will take the first and maybe Ben can think about the second because it’s a very important country for us remain so in post divestment. And a simple answer to the first one, ultimately having made the offer, we are not really allowed to buy any stock anything less than the offer we made. And so it’s not an option open to us.

Clearly the major op funds are playing a part in the moment and if you assume that they typically look for a 10% return over a annualized basis, but we have said it could take up to a year to complete that there are dividend differentials in between. The difference is reasonably easy to explain. So it’s not a concern to us and yes, I can confirm that.

There are no prima facie reasons why we should not complete. We know the regulatory processes. We’re just probably testing the edge in terms of scale and scope of a couple of the countries such as Brazil and China.

And Ben, Nigeria?.

Yes, Nigeria, well first let me also add my very very positive reaction to the fact that the transition so far has been very peaceful and without disruption or security or safety risk to Nigeria in general and also on our operations and people in the country. Of course Nigeria remains a very important country for us in many ways.

It is a huge resource base. It’s also a very significant resource base where we can get access to in terms of gas, in terms of the integration into LNG and in terms deepwater, Bonga Southwest being just one of a number of very attractive opportunities for us there. So we will continue to take a look at Nigeria with a view if you want to invest there.

We have been as you know on the journey to gradually reduce our exposure to onshore oil there. We see the risk reward balance being appropriate but it would be completely different of course for onshore gas for domestic purposes, onshore gas into LNG which has been a very very robust and successful business and as I said deepwater in Nigeria.

All these businesses have been robust in terms of returns, have been also quite resilient despite the challenges that quite often are attributed to Nigeria and are fundamentally very very attractive.

Of course we will take a view generally on all the aspects of country risks like we do for many countries for that matter also in the Netherlands and the UK, so don't think for a moment that Nigeria is just out there in a special category and we will look to take our decisions in the context of a good appreciation of that risk and adequate reward for it.

But I think that is going to be available in Nigeria going forward, certainly given the prospectivity of the country. .

Thank you. The next question is from Rob West from Redburn..

My first question is again on integrated gas business and I am trying to get a sense of moving parts there. You’ve gone from I think 3.2 billion contribution to earnings in 1Q ’14 to 1.2 billion this quarter and clearly you had one of the two trains offline in the quarter at Pearl and some of the impact of lower gas prices.

I know sort of getting a more detail on Qatari taxes, the chance of that tied to the unfractured shale reservoir.

But anything you say around that, I would be interested in sort of the trajectory of where that’s going and so as Pearl comes back and extra gas lag? And then secondly, on Brazil, so I think that’s clearly one of the best assets in the whole industry that you’ve gotten exposure to from BG below the ground and Petrobras has some challenges with balance sheet and financing, but you look really really good.

And in terms of increasing exposure there, what are your options to accelerate value creation, is there anything you are looking at in terms of extra ways to help make sure the right amount of investments go into those assets?.

I will take the first one and Ben, do you want to comment on the second one, on Brazil because again that’s quite a strategic element to it. The integrated gas business is relatively simple. There are three elements around 0.5 billion, 500 million each. The first is a tax move in Australia.

Second is the gas to liquids turnaround and third is the LNG trading business relative to the spot prices we’ve seen last year of 20. You are talking single digit this year of course, the rest is just pure LNG pricing across all of the different activities we have.

So those numbers are very much rounded in approximate but that’s the basics that’s there year on year. Of course the 500 million Australian, I could claim it’s a one-off, it’s actually happened three times now, in the past three quarters. But it’s entirely driven by the FX.

Ben, Brazil?.

Thanks Rob. Brazil indeed – you have to be right, it is a very very strong asset and we of course hope to -- and expect to make the most of it.

I'm also very much about Petrobras challenges but as I said earlier on I am also confident that Petrobras which is after all a very very competent organization on many fronts will be emerging from this as a stronger company as well.

Having said that, you are obviously right also that they have announced a significant divestment program which is going to spread across the upstream, downstream and midstream. And we will be looking at what else -- what comes out of that.

If you look at the exposure that the combined company will have by the end of the decade to Brazil it's going to be of course significantly higher than what we have today but in my mind it is going to be low enough for us to have appetite for more especially considering again the tremendous attractiveness that sits in that resource base.

So we have indeed things worth to be offered up in Brazil, in areas that understand, we would only look at it with keen interest but of course it would have to be of the right value for us to consider it. .

The next question is from Hodee Bertrand from Raymond James..

Two quick questions and coming back on final investment decision in ‘15 in the quarter Appomattox. Looking at the development costs in the offshore let’s say over the last 12, 18 months where – when we look at the kind of development cost project has been launched, it was in the range of $25 to $30 per barrel range.

And my view is that it’s clearly not compatible with creating value at around let’s say at $70 per barrel. So what will be the criteria you will use to test and launch a project like Appomattox? And then the second question on Appomattox. Simon, I understand you referred to a deadline into ’16.

If you don't take your final investment decision on Appomattox, you have to relinquish the block, is that correct?.

Thanks for the question and simple answer on the second one is probably, we think it’s always negotiable but the aim is to take our decision and we are well in place to do so. Then what would drive the decision criteria, obviously unit development cost is one of those because it impacts the return.

So fundamentally it’s returns, net present value and confidence that we can deliver because there is always some level of uncertainty both in construction but also subsurface. The Appo is relatively unique because it's a new player in the Eastern Gulf.

It is at the moment Shell is the only company really drilling there but there is more exploration potential as well. We will need to look at pipelines to ensure evacuation reach as well but having constructed the ability to make more from the first hub in any given area, particularly if you have developed the infrastructure is well established.

It’s been the core of our development of value in areas from Mars basin through to the recent Perdido development. It is how fundamentally you make good returns on your first investment but excellent returns on all the follow-up.

So Appo is very well-placed to be a good project at the first investment decision but then to be a hub to capture value for many years to come. So in totality it’s most likely to make the cuts in return terms and affordability. .

Thank you. We will now take the last question from Asit Sen from Cowen and Company..

Ben, just wanted to come back to your comments on Brazil. Brazil has always offered very good promise but operational reality has always been different. Two questions for you if I may.

Based on your recent visit what did you see or hear that makes you incrementally more positive and second, as investors what should we be focused on to figure out if things are really getting better? Are we looking at local content policy issues, supply-chain issues, pre-sold policy changes, what should we be looking at?.

Thanks Asit. Yes, you have to be right, Brazil is a country with a lot of promise and I'm sure that as investors you will look at it in a mixed way as well. I think for us it has worked actually very very well. Brazil has been for the investments that we have made there, including the downstream assets of course has been very very good country.

The only thing wrong in my mind with Brazil was -- that it was just too small and that we needed to have more exposure to it. Now can we be more positive about what is going to come? I’d be a bit hesitant to comment on that.

It’s always tempting to think that of course with the distresses that Petrobras may be under financially, the opportunities that may be there from divestments, the need and desire from the government and Petrobras to be successful, very successful in the presold may be the realization that local content policy is also giving inefficiencies and constraints.

It is very very tempting to just look at and say well surely opportunities must confirm that. Again let me just say that they have not been corrected in to the way we have valued the BG assets there.

But if anything and that is just nothing more than an observation and a single data point, yes, I have come away from Brazil, remaining optimistic in all these areas but again it’s not factored in. If it comes it will be upside but I do believe and this is also why this is a shaping move for us.

We will be if the deal indeed closes we will be fantastically well-positioned for whatever opportunity that will come our way in Brazil. End of Q&A.

Okay. Thank you very much. I think that concludes the call today and thanks for joining and sharing the event with me. Second-quarter results scheduled to be announced on July 30, 2015 and Ben and I will be back to talk to you again then. Thank you and have a good day. .

This concludes the Royal Dutch Shell quarter one results announcement call. Thank you for participating..