Simon P. Henry - Chief Financial Officer & Executive Director.

Oswald Clint - Sanford C. Bernstein Ltd. Lydia R. Rainforth - Barclays Capital Securities Ltd. Christopher Kuplent - Bank of America Merrill Lynch Jon Rigby - UBS Ltd. (Broker) Biraj Borkhataria - RBC Europe Ltd. (Broker) Irene Himona - Société Générale SA (Broker) Martijn P. Rats - Morgan Stanley & Co. International Plc Thomas Y.

Adolff - Credit Suisse Securities (Europe) Ltd. Alastair R. Syme - Citigroup Global Markets Ltd. Lucas Hermann - Deutsche Bank Anish Kapadia - Tudor, Pickering, Holt & Co. International LLP Guy A. Baber, IV - Piper Jaffray & Co. Rob West - Redburn (Europe) Ltd. Jason Gammel - Jefferies International Ltd. Aneek Haq - Exane Ltd.

Thijs Berkelder - ABN AMRO Bank NV (Broker) Asit Sen - CLSA Americas LLC Jason S. Kenney - Banco Santander SA (London Branch).

Welcome to the Royal Dutch Shell 2016 Q1 Results Announcement. There will be a presentation followed by a Q&A session. I would now like to introduce your host, Mr. Simon Henry. Please go ahead, sir..

Many thanks. Ladies and gentlemen, welcome to today's presentation. We announced our first quarter results this morning. These results included two months of contribution from BG following the completion of the acquisition on February 15.

We've taken the opportunity to enhance our financial disclosure across the company today, and I hope you will find the new figures useful, although I do appreciate some of the modeling challenges it may now bring. Let me give you a summary, and then of course there'll be plenty of time for your questions.

Before we start, just let me highlight the disclaimer. Shell's integrated activities from the wellhead through to the customer do differentiate us with our Downstream and Integrated Gas businesses delivering good results, underpinning our financial performance despite the continued low oil and gas prices at $34 average Brent for the quarter.

We delivered $1.6 billion of underlying current cost of supply, or CCS, earnings this quarter, $9.3 billion of similar earnings over the last 12 months. We're already seeing positive effects from our acquisition of BG. BG delivered strong production growth in this quarter and some $200 million straight to the bottom line.

We're off to a good start with the integration, building on six months of detailed planning before the deal was closed, at the same time continuing to reduce costs and spending overall across both portfolios with material opportunities to do exactly this in the down cycle.

It's early days, but we're extremely pleased with what we have seen so far from the acquisition. Turning to the results, and I'll start with the macro. We've seen a sharp decline in oil and gas prices compared to the year ago, reflecting primarily the OPEC policy change.

Brent oil prices were some 37% lower than year-ago levels; similar declines in WTI and the other crude markets. The realized gas prices were some 36% lower than one year ago with a strong decline in gas prices seen in all the markets.

We appreciate there has been a recent recovery of prices during April, but this does relate to the fundamentals of supply and demand. But it is far too soon to be calling a break in the weaker environment.

On the Downstream side, the refining margins were significantly lower in all regions driven by oversupply, higher inventory and a relatively mild winter in the US and in Northern Europe.

Chemicals, the industry cracker margin strengthened in Europe and in Asia (3:15) last year and was driven by the further reduction in naphtha feedstock costs due to the decline in crude. US gas cracker margins also declined as ethylene prices continued to fall over and above the decline in the gas price.

You will I hope have seen the enhanced financial disclosures from the company this quarter. We now report Integrated Gas earnings separately from the Upstream, rather than as a subset, and in more detail than in the past.

In Downstream, we'd given an earnings split formally, with a combination of refining and trading, obviously separate from marketing. Also taken on board some comments around the exchange rate impacts, which have been a bit noisy over the past couple of years in terms of quarterly impact.

So we're now treating noncash foreign currency impact in Australia and Brazil, and specifically on the deferred tax assets, we're now treating them as identified items. So you'll see a restatement of that in the results tables today, both explicitly and also implicitly in the businesses.

As this effect was large and a positive this quarter, had we reported on the prior basis, the underlying earnings would have been higher by some $570 million. Excluding identified items, Shell CCS earnings were $1.6 billion. That's a 63% decrease in earnings per share from the first quarter last year.

And that EPS figure for Q1 uses the weighted average number of shares in the quarter, and clearly that changed during the quarter. Much lower opening balance, 1.5 billion roughly shares, roughly higher by the end of the second quarter due to the acquisition of BG.

On a Q1-to-Q1 basis, we saw an increase in the loss in the Upstream and lower earnings in both Integrated Gas and in Downstream. Return on the average capital employed was 3.8% excluding identified items, and cash flow from ops was around $650 million or $4.6 billion excluding working capital movement.

Dividends distributed in the first quarter were $3.7 billion or US$0.47 a share, of which $1.5 billion, $1.5 billion, were settled under the Scrip Programme.

Turning to the business segments in a little more detail, Upstream earnings excluding identified items for the first quarter 2016 were a loss of $1.4 billion but with $2 billion of positive cash generation excluding working cap. Low oil prices dominated these earnings. That's a $1.4 billion effect compared to a year ago.

However, I think it's very important to point out that the actual operating performance continues to improve. The focus on margins, reliability and uptime, it is delivering. You can see the increase in underlying production contributing, and we also have a decline in the operating costs.

Turning now to Integrated Gas, earnings there were $1.0 billion in the quarter, and that compares with $1.5 billion a year ago. Lower oil and gas prices reduced these results by some $700 million, and results also exclude the dividends from the Malaysian LNG Dua joint venture, which last year were $90 million in the first quarter.

We exited that joint venture in May last year. Uplift from BG increased the contribution from trading, and lower well write-offs, they all combined to deliver a profitable quarter despite the lower oil price.

The headline oil and gas production for the first quarter was 3.7 million barrels of oil equivalent per day, 16% higher than the first quarter last year, and the uplift from the BG acquisition accounts for the majority of that increase.

So let me also note we're seeing the benefits of Shell's actions to improve the uptime, less maintenance than the year ago, better reliability and uptime for example in the UK and in Malaysia. All good to see. The LNG volumes were also higher, mainly reflecting higher volumes as a result of the BG combination.

Turning now to the Downstream, earnings there for the quarter excluding identified items were $2 billion, mainly due to lower results in oil products.

In oil products, the refining and trading results were lower than in the same quarter last year, and that reflected the weaker global refining conditions across the board and also reduced availability due to downtime, particularly in the Bukom refinery in Singapore.

Marketing delivered strong underlying performance for the quarter, results at the same level as last year in fact, driven by higher unit margins and lower costs. Chemicals earnings were 8% lower than the year ago.

That was due to the lower margins in the US base chemicals, noting the margin, excess (8:54) margin, and the downtime again at the Bukom refinery in Singapore. This was partly offset by lower costs and recovery and production at the Moerdijk site in the Netherlands. But overall, another good quarter for the Downstream.

Return on average capital on the clean CCS basis was 18.8% at the end of the quarter on 12-month basis, and the Downstream CFFO, cash from ops, was around $11 billion over that same 12-month period. We made several announcements on the Downstream portfolio during the quarter.

In the US, Shell and Saudi Aramco decided to end the Motiva joint venture on the Gulf Coast. We're dividing the refining and the marketing assets (9:39) between us. We have recently completed the sale of the Denmark marketing business for around $300 million.

We also delivered a $400 million MLP equity offer in the Midstream pipeline company in the United States. We expect complete the Showa Shell divestment in Japan and the sale of shares in the refinery company in Malaysia this year.

Taken together, the Showa Shell, Malaysia, Denmark and the typical MLP yearly deals should result in around $3 billion of disposal proceeds this year, and together with potential contribution from the Motiva dissolution, that's pretty good start for the year. Turning now to the cash position.

Cash from ops on the 12-month rolling basis was $23 billion at an average Brent price of around $48 per barrel. That's pretty close to today's spot. Cash portion of the BG deal was $19 billion. That resulted in a negative free cash flow position in total for the quarter.

The net debt position, which is around $69 billion, now reflects the total BG balance sheet and of course the purchase price paid for that. Gearing at the end of the quarter was 26.1%. We recognize certain operating leases from BG as financed leases. These include FPSOs, some of the shipping vessels and one LNG facility.

Overall, the BG deal added some 9%, nine percentage points, that are gearing, and 2 percentage points of that is as a result of effectively the financed lease changes. Priorities for cash have not changed, first debt reduction, then dividend, then capital investments and share buybacks compete for the margin.

Dividends declared were $12.7 billion over the last 12 months. Now more specifically on the BG consolidation, because it was quite a significant one-off impact. The final transaction price for the BG acquisition was $54 billion or some £37 billion. We'll find details of the accounting impact for BG in the results announcement.

But the headlines, goodwill was $9 billion. Now this is an accounting definition and artifact, if you like. Goodwill is the balancing number between the fair value as seen by market participants and the purchase consideration, the $54 billion.

So under the accounting standards, fair value is calculated using forward price curves as at the day of completion for the first two years, and then analyst macro forecasts thereafter.

So just a reminder, the oil price on Feb 15 was around $33 a barrel, therefore the forward curve was fairly low, and this did impact a lower fair value and therefore a higher goodwill. The profit and loss account going forward will include annually a $1.2 billion after-tax depreciation charge for the purchase price premium.

That's basically $100 million a month. So we had a $200 million impact the first quarter of 2016. It will be $300 million in quarters going forward. Let me now just move on to the ex-BG assets and their performance. We will of course talk about this somewhat in more detail at the Capital Markets Day we're having in London on June 7.

However, it's great to see that the former BG asset growth really is coming through now in this quarter. The oil and gas production from these assets averaged around 800,000 barrels of oil equivalent a day in the first quarter.

That's 25% higher than a year ago, and it's a third higher than the production that was in the public domain when we negotiated and announced the bid. Their production in 2014 was 600,000 barrels a day. In the first quarter accounts for Shell, the share we booked, only two thirds of this amount, 522,000 barrels a day oil equivalent to be precise.

And now obviously that reflects just two months of contribution. The growth actually comes from the ramp up of Queensland Gas in Australia and also the sixth and seventh nonoperated FPSOs in deepwater Brazil. BG's assets overall added around $200 million to Shell's earnings in the quarter, and approximately $800 million of cash flow from ops.

Still early days, but the synergies program is on track, but it's actually more than on track, and you will have seen some announcements recently to reduce our United Kingdom office presence.

Based on the excellent progress that we made in the detailed integration planning, we are likely to see delivery of the synergy targets much earlier than planned and at a lower than expected implementation cost. So overall, great start with the integration and obviously a lot more to come there. Before I close, a few words on spending.

We continue to reduce capital spending and operating costs. We're reducing those costs across the board, redesign, postpone new options.

Earlier this year, a few months ago, we provided the capital investment guidance for 2016 of $33 billion, potential to reduce that figure further, because of course we hadn't actually got under the hood of the BG portfolio at that point. Now capital investment for 2016, this is the actual results, is clearly trending towards $30 billion.

We look at detail at the BG portfolio. We continue to drive more capital efficiency in our own opportunity funnel, and in practice we're taking costs out of projects, and projects add to the funnel.

The $30 billion figure, and just to be clear, in 2014 before acquisition, before we started either company working on reductions, the combined capital in 2014 was $47 billion. So this $30 billion figure is 35% below that level.

It includes, and it actually includes well over $1 billion of noncash items for financed leases still to come this year, a couple of FPSOs in Brazil and Stones in the Gulf of Mexico.

On operating costs, similarly the underlying operating costs are trending downwards to a run rate of around $40 billion by the end of the year, but during the year we'll take a few one-off costs most likely associated with the transaction, which is why we don't give a full-year figure.

But that $40 billion compares again, go back to 2014, we're something $52 billion, $53 billion, 20% lower than the 2014 combined level. So in simple terms, we were saying all through last year judge us on what we do, not what we say we're going to do. We're effectively taking $17 billion after the CapEx and $13 billion after the OpEx.

That's $30 billion, three zero billion dollars, out of the spend between 2014 and 2016. And in very simple terms, we are expecting to absorb the entirety of BG's activity, OpEx and CapEx, and keep the spend level in both cases at the same level it was for Shell alone in 2015.

And that's all a result of what I would humbly suggest is a world class integration process that has been running since July last year, and has really hit the ground running, both teams BG and Shell.

So just to summarize again then, integrated activities, wellhead through the customer, two differentiators, Downstream, Integrated Gas, both delivering good results, underpinning the financial performance despite $34 oil and $2 Henry Hub. We're already seeing the positive effects from BG.

We're very busy now combining the two companies, looking to add yet more value for shareholders. At the same time, we're continuing across the board reduction of costs and spending, lots of material opportunities out there in the down cycle. Early days, very pleased with what we're seeing so far from the acquisition.

So with that, let's take your questions. I sort of raised it earlier, but I do acknowledge for all of you out there, we have changed some of the reporting segmentation, and this may be making some of the modeling quite difficult. Can I suggest that we don't cover those on the call, and that we can follow up with the IR team primarily.

I'll do what I can to help, but it may be a distraction for the main points in the call. So also I'll remind you we're having a Capital Markets Day in London on June 7, when hopefully everybody on the call will be able to join us. And so please could we move to questions, just one or two each so that everybody has the opportunity.

Operator, please could we poll for questions? Thanks..

Thank you, sir. We will now begin the question-and-answer session. Our first question comes from Oswald Clint from Bernstein. Please go ahead. Your line is open..

Thank you very much. Yes, Simon, thanks. Two questions. First one, just on the Upstream business itself, you spoke about the reduction in the OpEx, which I can see, but obviously on a country basis we see here in the segmental that your loss making in every geographical business this quarter for the first time.

So OpEx has fallen, your uptime is good, reliability is good. Is there more you can do here to get this, the Upstream, across these geographies back kind of into the black? Is that going to be sufficient for 2Q? Or maybe if you could just talk about further cost reduction across the geographies.

And then second question, just on the CapEx kind of trending towards $30 billion. I think, I'm pretty sure investors are going to find that a little bit vague.

So I'm wondering, does that mean you feel confident about $30 billion? Could it, will it be above that? Is there a chance it could fall below that? Just a bit more clarity around that CapEx number, please. Thank you..

Sure. Thanks, Oswald. The primary driver of the Upstream numbers is a $34 oil price, plus the fact that even where we're producing gas though, the linkage to the oil price with some lag in some cases. So that fundamentally is the difference.

At today's price, $45 when I last looked, would be roughly $1 billion better off across the board, which moves some of the regions back into place. The fundamental reaction though, you're absolutely right, is costs. We've made clear to the organization some time ago, and we are seeing the bottom line results coming now.

Thinking about costs, the combination of BG and the $40 world is a fantastic opportunity to take costs out forever, as long as you think about the costs, the price being low forever, and ensuring that costs don't come back again when they go back up. So very strong focus on cost, and that will come through.

It's difficult to do $1 billion in a quarter, but it is certainly progressing in the right direction, and there's more to come. There will be asset sales. We'll see that. And we've been looking very closely at some of the more difficult areas, shall we say, of costs such as the North Sea, and therefore working hard in that.

As we go forward, you are going to see some new production coming on in places like Gorgon, all of that's in Integrated Gas of course, and in Kazakhstan and in Stones in the deepwater. And we will see the BG synergies kicking in, although quite a lot of that in the first year is on lower levels of expiration.

So all of those things contribute, and I mean each in their own small way. The biggest short-term factor is clearly the oil price. At trending towards $30 billion, what does it mean? Well, firstly we genuinely only have now 10 weeks under the hood in BG and looking at the actual CapEx program.

Before that, we did have six constructive months where we were limited in what we could share for legal reasons, but extremely constructive process during integration, so, or the planning for integration. So we do have a reasonable view about what some of the choices are. The actual CapEx in quarter one was $6.5 billion.

That's rounded up to include the January spend at BG. So multiply that by four, you come up with a number less than $30 billion. You look at the 12-month number, it's slightly above $30 billion if you include BG. So we're heading directly for $30 billion, and we're making basically decisions as we go along at the margin.

I would expect we'll hit $30 billion or below as we go through for the total for the year, because that's what the trend is telling us, and we were finalizing that really over the next month or so ahead of the Capital Markets Day.

There is an issue around rig commitment in terms of potentially idle rigs and what we choose to do with them, has some noise impact because they're in OpEx. It could appear in OpEx. It could appear in fx (24:26). It could appear in CapEx, which is why I'm slightly reluctant to commit to a very specific number.

But it will be $30 billion or thereabouts I think, 90% already committed. So hopefully that helps, Oswald. Longer chance but I think it's a question that quite a lot of people will be looking to hear the answer to. Thank you very much.

Can we move to the next question, please?.

Our next question comes from Lydia Rainforth from Barclays. Please go ahead. Your line is open..

Thanks. Good afternoon, Simon. Two questions, if I could. The first one was, and I come back to focus on the OpEx side. If I look at the chart that you show, the move from 2015 to 2016 seems to imply about $8 billion reduction, which are clearly more than the $3 billion standalone guidance for Shell cost reductions and the $2 billion synergies.

Is that the right way of looking at it, that you're actually doing more on the cost savings than you might have expected coming through? And that partly links to the second question of, are you able to give what you think is now the cash flow breakeven to cover CapEx and dividends in terms of an oil price either be it for this year or next year? Thanks..

The reduction between 2015 and 2016 that we're seeing effectively, I'm using a ruler there, it's not necessarily $8 billion because we're trending towards a run rate of $40 billion. So we might end up with slightly more than $40 billion in the year because of one-off items in the first part of the year.

But broadly speaking, it's $47 billion down to a run rate of $40 billion in the year. And yes, we are seeing more opportunity than we had originally expected. We previously stated $38 billion for Shell and add on a bit for BG, which is not necessarily all being accounted for on the same basis.

But all told, all integrated, we should be at a run rate of $40 billion by the end of the year. And this is coming from a variety of places but one big help is synergies basically emerging much more quickly than we had originally sort of planned for or expected.

And that's both on the exploration side, which we've been working at now for six to eight months, but also on the OpEx side where it's clear we can absorb in quite a lot of areas whether it's at the corporate budget level or in one or two countries. The activities with no added, no increase, net increase in staff or cost.

And so that's been a big driver, plus I think momentum. We talked last year about lots of, not small, but for you as observers probably not that material, $100 million here, a few hundred million there, quite a few ongoing initiatives which are continuing. And they took cost out last year and taking more out this year.

So it's aggregation of the contributions from many people. The 90,000 who are in Shell and not just something that Ben or I are exhorting people to do. Could be further room as we go forward as well. I expect obviously with the oil price being where it is, that's very much the direction we will take. Does that cover everything, Lydia? Okay. Yeah.

Next question..

Next question comes from Christopher Kuplent from Bank of America Merrill Lynch. Please go ahead. Your line is open..

Yeah, hi. Thanks. Good afternoon. Simon, just two quick ones. I just wanted to check, I think you've now got almost $70 billion under your definition of financial net debt. The free cash flow obviously is still negative in Q1. I guess will remain negative this year.

I just wanted to check how worried you are on the gearing side of things and whether that $70 billion number is causing alarm clocks, sorry, alarm bells as well to ring.

And secondly, just wanted to get my hand around again the $40 billion OpEx, whether you could give us a bit more detail where that OpEx actually sits, what you include in there, how much you would define as structural costs that are not coming back should the oil price recover into the next three years.

Or indeed, how much of those savings are purely pricing and cyclical. Thank you..

Okay. I'll try on the second one. The first one is the really important point, $69 billion of net debt, yes it is something that I might lose sleep about, but not just yet, 26.1% gearing.

Free cash flow negative in the first quarter obviously driven by the BG deal and the working capital of $4 billion to $15 billion there that impacts the free cash flow. And the $34 oil price didn't help either.

So going forward, in the short term at $45, with the current level of spend, the gearing and the net debt is likely to go up before it goes down. What brings even at $45, so what brings it down? It's the continued reduction in OpEx. It's the continued reduction in investment level, and importantly it's the coming onstream of new projects.

And none of these are easy fixes. So I'm confident, very confident, that the right things are being done. What we need to do is do them at pace and ensure that we are delivering sooner rather than later, which is why it's great to see BG synergies coming in as we see.

The gearing figure of 26.1% is a couple of percentage points higher than previous advice, and it's driven entirely by the treatment of the leases, the financial leases rather than operating leases. And it had no impact, or little impact, on the credit rating, because the rating agencies look through that.

But it does mean that any statements made around gearing, you have to sort of add 2 percentage points onto any previous statement of expectation, and that figure will also be impacted going forward by new FPSOs as well of course. So a manageable situation, but not one that has any easy fixes. But I think all the right things are being done.

The credit rating agencies have taken a close look and Moody's has brought most of the industry down. We came down to AA with Moody's. S&P we're at an A+ rating at the moment, and that is still with a negative outlook.

So we are looking at effectively how our future performance benchmarks against those metrics as a key performance parameter for the management. So both debt reduction and increased cash flow generation are required do get those metrics back into the right place.

At a $40 billion OpEx, here's the high level breakdown, it's half and half upstream/downstream. So $20 billion (31:36) is only the Downstream and the $20 billion Upstream is split two thirds, one third between Upstream and IG.

That's after allocating everything to the businesses, so around about $10 billion of the $40 billion is what you might think of as corporate-type costs, finance, IT, real estate, HR, et cetera. The reductions that we've talked about are coming across the board.

Many are linked directly to reductions in the number of people by changing the way we do things or changing the way we do the work, different relationships with for example suppliers, not just on unit rates but fundamentally changing the way we deal in standardized design, different way of handling IT, et cetera.

So it's not something we started three months ago; it's something that we started three to five years ago depending on the area we're looking at. Therefore, we're pretty confident most of what we're doing will stay at if the oil price does recover at some point in the future.

Clearly at the margin where we're in the first-party services, our big suppliers to us, but there is exposure if the oil price comes back. But to be honest a lot of the savings that we've seen so far have been in for example areas like drilling. It's been better performance as much as there have been low unit rates.

Or it's been in areas of activity such as the North Sea, where reducing costs is not the nice to have, it's an imperative or facilities will be closed in. And therefore, some very significant changes in the way of doing things that will not be reversed in the event that oil prices go back up.

So we're quite pleased with what we've been seeing so far and let's see how much further there is to go. Many thanks, Chris, and hopefully again both questions quite relevant to most of today's audience. Next question, please..

Our next question comes from Jon Rigby from UBS. Please go ahead. Your line is open..

Thank you. Hello, Simon. Two questions.

Could I just ask a question on the LNG? I think you said that this is about a $200 million contribution from BG, so can you confirm that or discuss a little more about what you're seeing in terms of sort of optimizing cargos? Are you able to see the kind of trading and optimization earnings that BG was able to generate? And is that starting to spread into the Shell business as well, the bigger Shell business? Maybe some color around that would be really useful.

And secondly just on chemicals, obviously Moerdijk coming back, but I think you referenced Bukom down. Is it fair to say chemicals is under-earning against where you'd expect it to be all things equal? And maybe are you able to sort of calculate or indicate what you think the delta might be if everything was running rather more smoothly? Thanks..

Thanks, Jon. Well, you're right on chemicals. It paid out versus $200 million, $300 million in Bukom. Moerdijk came back, but essentially the ethylene cracker in Bukom has been down.

Should come back in the middle of the year plus or minus the end of Q2, but you are talking a few hundred million dollars, if you like, left on the table compared to everything running smoothly. LNG optimization, now still a bit early days.

I don't want to say too much with some commercial sensitivity here, but I think we're seeing just as much flexibility in optimization in the Shell portfolio as there is in the BG portfolio. But it's a great opportunity to learn from both sides how to optimize not just in the short term but the medium and the long term.

And in very simple terms, Shell's traditional approach was supply driven and BG's traditional approach was market driven, start with market, work backwards to supply and vice versa.

So as the two meet in the middle, and you may be aware that Steve Hill, who used to run the GEMS business for BG is now running basically same business but twice the size for Shell plus BG, and having Steve there plus the guys who worked on our portfolio is indeed identifying further opportunities.

But certainly in the short term, interestingly optimization is just as positive from the Shell portfolio as BG's. Although one has to say at this particular point in time, neither of them is as lucrative as they have been in the past, but it's a great point for the future or opportunity for the future.

I'd just take this opportunity to note, we've now got two volumes in for LNG, which are indeed effectively the share of equity production, which is about 7 million tonnes in the quarter. So you're looking at over 30 million tonnes on an annualized basis.

And we've also shown the Shell share of effectively the sales, because in BG's portfolio and increasingly in Shell's portfolio we're lifting other people's production and selling it.

So our share of sales is actually 12 million tonnes in the quarter, and therefore fully annualized you're talking around 50 million tonnes or 20% of the world market in terms of Shell equity volume here (37:04). So it gives you a feel of the scale and the opportunity. Thanks, Jon. And good luck against Brighton on Saturday. Next question..

The next question comes from Biraj Borkhataria from RBC. Please go ahead. Your line is open..

Hi, Simon. Thanks for taking my question. I had a couple. The first one in looking out Upstream Americas or North America now as it's stated. CapEx was down quite sharply Q-on-Q by about $1 billion.

I was wondering if you'd talk about the unconventionals business, specifically in kind of post the departure of management there and how that fits into your overall portfolio as well as how much capital that business will get for 2016 and going forward. And the second question was more of a clarification really.

I noticed the Oceania gas realizations were particularly weak in the quarter versus the run rate, and I was wondering if you could give a bit more color on what's going on there. Thanks..

Sure. Thanks, Biraj. The unconventionals business in North America and Argentina together is getting about $2 billion of capital allocation this year. That's quite a lot down on previous years, and we're getting a lot more for it as it happens, because they keep coming in ahead of target.

About 70% of the wells are coming in with a 1,000 barrel a day initial production or better. And we're seeing costs continue to be down sort of 20%, 30% like-for-like year-on-year. But the majority of the activity still remains exploration and appraisal.

We've rarely if at all pulled the trigger on major developments for obvious reasons, $2 gas and $34 oil is not the time to be doing major development. So it's a bit of in a holding pattern. Strategically we're in a good place.

We've got now in terms of resource potential, you're talking up to 12 billion barrels of oil equivalent resource potential across Canada, United States and Argentina. Around three quarters or 70% or so of that is gas, and we have the balance sheet value is just under $15 billion. So you've got massive resource just over $1 a barrel.

I think over time this is going to be great value to develop, but in the short and the medium term, it'll be on a pretty much a care of maintain capital allocation. The Oceania gas realization, and ultimately this is driven in part because what you see is a net back.

So it's a net back both in Queensland and in Western Australia, and therefore the realization, net back to the LNG price, it's linked almost directly to the LNG price.

Once you've deducted the, effectively the way Queensland Gas is being structured with tolling agreements and pipeline tolling, once you've deducted the costs of taking the gas from the wellhead, liquefying it and getting it to market, that has basically driven down the average realization price.

All of the price upside gets shown in the upstream rather than the midstream in practice, but that's just the nature of the BG set up in Queensland. But it's also not dissimilar in Western Australia, at least in terms of the realizations that we would recognize. Okay. Many thanks. Next question, please..

Your next question comes from Irene Himona from SG. Please go ahead. Your line is open..

Thank you. Hello, Simon. My first question is on volumes, if I may. You highlighted the contribution of BG to Q1 production and LNG.

Are you able to provide some guidance on the new group's production in full-year 2016 and 2017 given all the moving parts of the puzzle? And then secondly, going back to the $40 billion, I mean effectively you're talking about faster near-term OpEx reductions as I understand it.

How does that relate to the $3.5 billion synergies from BG by 2018? I mean is it the same number happening earlier? Are you able to raise that? And is there anything you can say at this stage on the question of value synergies or over and above that number, which I understand had to be strictly sort of audited? Thank you..

Thank you, Irene. Volumes, if we had three months of BG rather two months, we'd have been about 3.95 million barrels oil equivalent a day, so quite a step up.

As we go forward, I cannot give you guidance simply because it literally is not on my radar screen, the production, because we're spending all the time on cash, what are we spending, what are we earning, and where are the priorities. So I hope production, to be brutally honest, apart from needing to be safe and reliable is an outcome.

It will obviously be impacted not just by divestments, but also new projects coming onstream as well.

So I do think fundamentally at the moment we're putting together the asset-level detail, the maintenance and the underlying spend program and we are aiming to put together a much firmer and clearer collective unified plan by the back end of this year.

So during this year quite a lot of what we say remains a little bit provisional although it will be accurate, and the targets for the individuals will be set in the back end of this year. So I can't give further guidance on the volumes.

The $40 billion, how does it relate to the $3.5 billion, well the $3.5 billion by 2018 was, if you recall, $1.5 billion of exploration, $2 billion of OpEx. Now the $1.5 billion of exploration is something that we will almost certainly deliver early, quite early.

I don't know if we'll actually get there this year, but we will get probably close this year. Of the $2 billion of OpEx, it's a bit harder work, but actually we're finding we're doing that much more quickly.

I can't say – again, don't actually have the exact figures, but a lot more than I originally expected when we did the prospectus, will be delivered this year. And it will also cost us less. We had said in the prospectus that $1.2 billion would be the total expected one-off cost of the acquisition.

It should be lower than that, and we will also most likely try and ensure that that cost is incurred all in 2016 and doesn't spill over into 2017. Those are the moving parts. Are we in a position to raise the number, clearly there are indications that there are opportunities from what I've just said.

I think it's somethings we'll probably revisit in a month or so, in time for Capital Markets Day. But at the moment, the focus is on achieving the synergies, not necessarily extending them, and we're seeing some great progress. The same is true on value synergies. What we are seeing is a combination of factors.

We need to understand not only the numbers in the BG plans, but also the psychology behind them, how optimistic or conservative are they, and how are they comparing with what's actually being delivered.

The actual asset performance is extremely good against the original BG plan to date, I must say, and therefore that might actually throw off, yes, there are some value synergies that we can bank earlier rather than later.

But we're definitely seeing lower costs in one or two areas, crucially in both Brazil and Australia, and that is helpful indeed, because they are by the definition the two most valuable assets in the portfolio. So, so far so good, but I can't be more specific than that. Thanks, Irene. And next question, please..

Next question comes from Martijn Rats from Morgan Stanley. Please go ahead. Your line is open..

Yeah. Hi. Good afternoon. I wanted to ask you a few things. So I listened to part of the media call this morning, and in there you sort of invoked a spirit of Mario Draghi by saying we will do whatever it takes to balance our financial framework over the cycle. And I was wondering if you could elaborate on that.

It sounded like you potentially had something specific in mind.

And also how far does the balance sheet gearing need to rise before sort of whatever it takes sort of really kicks in? The second question I wanted to ask is with regards to operating cash flow in the quarter, even taking into account low oil prices, there's sort of the $4.6 billion ex working capital looks a little light.

And I was wondering if some of the one-off costs related to the acquisition, some of the sort of $1.2 billion figure that you also just mentioned might already have been in there whilst not taken as a specific, sorry, as an identified item?.

Okay. Thanks, Martijn. Yeah, what I actually said this morning was in response to a question, so what's your break-even price in cash terms. And so far this afternoon, you've all been kind enough not to ask the same question, which you probably would have got the same answer.

We don't have one was the answer because I would paraphrase Mario Draghi, we will do whatever it takes to balance the cash flow through the cycle, because actually there isn't an alternative if you want to quote somebody else. Importantly, it's through the cycle. So the aim is not to achieve any given breakeven point in any given year.

So I also quoted going backwards, previous 12 months is $61 billion, to 12 months in 2015, breakeven was $55 billion or around $70 billion excluding divestments. But clearly that needs to come down a little bit if we are to stay in business, and therefore we will do whatever it takes.

And that means reduce OpEx, reduce investment further, ensure that we deliver projects, keep them up and running, maximize the margins and divest assets. The biggest short-term factor will remain the oil price. The second biggest is in practice divestments. So that's one we can't control, the other we can.

But after that it's investments in OpEx, and we've already talked about that. So you can see we're doing whatever it takes in those areas. How far does gearing need to go before we're in that situation, we're in that now.

We always knew we would be post BG, but the credit rating metrics I referred to earlier, the actual numbers today would not necessarily mechanically support the ratings that we currently carry. We need to improve the ratings, and that is clearly stated by the rating agencies. So we need to start to reduce the debt. It's simple.

That's priority number one. We are in that situation now. $4.6 billion of working capital looks a little weak, was the premise. Yes, perhaps.

Yes it's got some one-offs, and it's got for example MDC (49:04) and paying for the deal, the present $300 million or so to George Osborne in terms of the cost of the deal, but that's less than $0.5 billion in terms of in the quarter in cash terms.

There are, there's always a few one-offs, but by and large the big factor was the working capital and the cost of sales adjustment, which ultimately some of those are one-off and some of those will reverse over time. I can't recall whether I mentioned it earlier, but there is a trading inventory. It's basically a contango play effect as well.

So that is reversible. The payment to the Iranians for their crude liftings a few years ago is not reversible, but it is one off. So those things will play through, and it's always difficult to look at one quarter alone to CFFO. Let's see how that goes going forward. Okay. Next question, please..

Next question comes from Thomas Adolff from Credit Suisse. Please go ahead. Your line is open..

Hi, Simon. Two questions as well, please. Just first one on CapEx, and I guess there's no such thing as an apples-to-apples comparison when we look at the reported CapEx guidings amongst the supermajors.

If we look at the $30 billion or so that you talk about, is that the right balance for short-term cash and returns and the longer-term health of the business? I'm kind of asking this question based on obviously today's cost environment, and it's clearly further cost reduction to come outside of shale.

The second question on the Lower 48, obviously Marvin left. The Lower 48 is now part of Andy's portfolio again. I think back in November you said we're going to try to run it independently.

And I think when I spoke to Marvin, he said I haven't quite figured it out whether it's the XTO type management, or whether it's the BP type management, which is truly independent. Have you figured it out yet? Thank you..

Thanks, Thomas. I shall have words with Marvin. On CapEx is $30 billion the right number in the current price environment, well, probably not. That's not where we're coming from. We saw $47 billion two years ago, so massive reductions. But even of what we spent today, some of that was committed in an oil price environment a lot higher than today.

So the unit rate of completing projects, think of Gorgon, Prelude, Stones, et cetera, Kashagan for that matter, (51:49), Galleon, those costs reflect a higher oil price environment, not today's oil price environment.

So to stay in business and maybe invest a little bit for the health of the long-term health of the business is probably lower than $30 billion at today's unit rate the costs that we would expect to see. So again, no specific, there's just less than $30 billion is what I would say. It could be several billion dollars less.

On the Lower 48, there certainly are two models out there, sort of the reverse integrations into an XTO-type model or the UVI internally. That could be conceived in practice. The team running the onshore shale business today, is the same team that was reporting to Marvin, they just now report to Andy.

What they have done is take huge amounts of costs out on the asset in drilling, and to the extent they're able to do in the aggregation and other facilities, what they and we are working on is the basically the above-asset costs. And how we deal with that will determine the answer to your question. It is coming down.

It's coming down across the board, part of the $40 billion. It's not yet decided that the specific answer to your question or whether there's a hybrid version. What I would like to think is if lower levels of above-asset cost is feasible for the shale business, then it should be feasible everywhere else in Shell.

So let's use that as the pilot to identify where we can go further faster elsewhere. So both of those are in progress at the moment. I think Andy will be with us on the Capital Markets Day, and I know he was in the US last week, so it'd be a good question to ask him.

Next question, please?.

Next question comes from Alistair Syme from Citi. Please go ahead. Your line is open..

Thanks. Hi, Simon. Two quick questions. One on OpEx, you gave a 2014 reference pro forma.

Can you give the 2015 by any chance? And secondly, appreciate the Integrated Gas and Upstream from an accounting standpoint, but does that distinction apply only internally? I know Martin and Andy are running the businesses, but are people allocated to these different businesses distinctly?.

On the latter, yes. I mean they are being basically run as separate businesses. We had, although we reported externally an IG segment, which is basically the same assets previously, the reporting lines were not unified, should we say.

So Martin is now directly accountable for activities such as Trinidad and Peru and all of the trading that is done through Steve Hill in Singapore. That's effectively how that works. On the OpEx, 2015 pro forma, it was basically interpolated between the two. It's somewhere around $46 billion give or take.

The reason I'm not slightly more specific is there are some differences in sort of definitions and accounting treatments. So it's close enough straight line between the $52 billion, $53 billion in 2014 and the $40 billion by the end of 2016.

Unfortunately, I don't think you can quite extrapolate that rate of improvement, but hopefully there's some improvement to come thereafter as well. Next question, please..

Our next question comes from Lucas Hermann from Deutsche Bank. Please go ahead. Your line is open..

Simon, hi. Thanks for the time. And by the way, thanks for the added disclosure, which is useful even though it will require a lot more spreadsheeting. Look, three brief questions if I might. Firstly, hard choices given where you're at.

Do you want to say anything around the Pennsylvania cracker timing, if at all? Secondly, just on cash flow, deferred tax and other provisions, and this is not the deferred tax adjustment you have been making quarterly, but deferred tax negative that's been running through your cash flow statement.

Can you talk through that in a little more detail? I mean the number has become increasingly large, and just sits there as a big negative with no real explanation.

And thirdly if I might, the operating cash flow in the Upstream business, which has clearly sunk over the course of the last four years, can you give us any indication through last year or into this year, what proportion of that comes from the deepwater, not the collapse, but the absolute today? What proportion is the deepwater that you suggest to us will deliver $15 billion to $20 billion of operating cash flow back end of this decade? And what proportion is the traditional Upstream engines business? That's it, Simon.

Thank you..

Thanks, Hermann. And apologies..

You can call me Lucas..

We have the same problem by the way. The hard choices, there are three or four big projects, and the first on the list is in fact the one that you related, the chemicals in Pennsylvania, the others being Lake Charles, Gulf Coast; LNG Canada, British Columbia; and Vito deepwater, Gulf of Mexico.

Further, there's sort of the big four greenfield, over which we could take a final investment decision in the next, well less than 12 months. It's highly unlikely that more than I would say two, maybe only one, but will actually go ahead in that timeframe.

And basically it's a choice of whether, what's the best way of retaining or maximizing value from that set of opportunities. The chemicals plant is probably the first one because of the timing of certain commitments that are already in place. It's an excellent project.

It's got a diverse set of market exposures and risks associated with it, and therefore provides quite some portfolio resilience relative to the rest of the opportunities, not just the big ones, but the smaller ones as well. We've had quite a lot of discussion. Not yet pulled the trigger on it one way or the other.

And certainly it's not a free option of course. There are costs of keeping the option open. So not a decision yet, but it actually is looking. If it were not a $40 world, it would be probably a very easy decision. It's a very strong and robust project. Deferred tax and other provisions, I will try not to go into too much detail here.

We just added a $6 billion liability as a result of the PPA calculation called, effectively the tax benefit of the step-up in fair market value of an asset has to be added back in, and that increases the deferred tax liability by $6 billion.

Elsewhere we have deferred tax assets as a result of making losses in countries such as the US and the UK, and we have deferred tax liabilities such as benefiting from capital allowances in countries such as the UK and elsewhere. So it's quite a complicated set of moving parts behind this.

The biggest issue for us and for analysts is are these tax assets recoverable, which by definition if they're on the balance sheet, they seem to be.

And the deferred tax liabilities will play out over time as the earnings come through from the assets to which they're associated, which the step-up of $6 billion that I just mentioned is virtually all in Brazil. Therefore you (60:01) Brazil produce and perform, that you'll see the liability reduce.

And deepwater production, just looking, is around 400,000 barrels a day at the moment, which basically is a combination of Brazil, US and Nigeria. And so that would be the Shell number. You'd have to add on BG. BG was running at approaching now 200,000 barrels a day effectively in Brazil. So you're seeing over 0.5 million barrels a day.

It's highly price sensitive, almost by definition. All of those areas have excellent exposure to higher oil prices, but at $34, that was a contributor to the negative. So it's probably the most price sensitive element within the Upstream business, and therefore, and it's also the piece that's growing.

So it's a big driver of the future, but it's not helping today. Okay. I think that's probably as much as I can say on that. Probably something we'll need to follow up as we do the Capital Markets Day work.

Next question, please?.

Our next question comes from Anish Kapadia from TPH. Please go ahead. Your line is open..

Good afternoon, Simon, couple of questions from me as well, please. And just following up on a couple of things. The first one was on cash flow. Looking at Q1, if we take the cash flow from ops, ex working capital and post interest, it seems like about $4 billion.

So if you take a full quarter of BG, feels like more like $4.5 billion or $18 billion annualized.

Is that a good basis to estimate cash flow off for this year using your sensitivities? Or are there any other kind of incremental factors, incremental cash flow that we should think of for the remainder of this year? And a second one on taxes, kind of following on from your last point.

You have seen a substantial increase in your deferred tax asset, and also your unrecognized tax losses.

I'm just wondering, with BG coming into the business, is there an opportunity to accelerate the use of these tax losses with some kind of BG's key profit centers such as Brazil and Australia?.

Thanks, guy. The simple answer on the second one is yes, but I can't go into too much further detail about that.

We need to be both clear about the best way of doing it and making sure that it's agreed with the relevant authorities, but bringing together effectively income generating assets and tax losses in a given country is an opportunity in at least two or three countries I'm aware of.

The cash flow estimate for the year, will four times Q1 suffice, well yes and no. It's not any one-off factors, minor quarter one factors get multiplied by four, positive or negative. So it's not the best way to look at it.

Maybe look at the four year, four quarters going backwards, which were actually at an average I think at $48 cash flow $23 billion and add a bit for BG is just as good as going four times Q1. But that in itself is not to be taken as a projection. It's just a little help with modeling, because there is always noise in the cash flow statement.

And remember that as we go forward, if oil prices do continue to rise as they did in April, we will increase working capital, and therefore there will be a working capital outflow. At the end of the day we work on the levers that we can, such as inventory levels and OpEx, and then the actual number to an extent will be an outcome. Many thanks.

Move on to the next question, please..

Our next question comes Guy Baber from Simmons. Please go ahead. Your line is open..

Thank you very much for taking my question. Simon, a couple from me. But you referenced the improved reliability in the Upstream.

Is there any way you can elaborate on that comment or perhaps quantify the extent to which reliability in the Upstream is improving your production performance? And I'm curious, in an environment where you're attempting to reduce spending and take out cost and there's a focus on integration, is there a risk that you may begin to lose some of those reliability improvements and how do you mitigate that? And then secondly, in balancing the cash inflows and outflows, you mentioned spending, costs and divestments.

You did not mention the Scrip Dividend, so I just wanted to get latest thoughts and comments around the extension of that Scrip program into 2017 or beyond and just what your most recent thoughts are around that program..

Thanks. Good points. The reliability year-on-year, our production performance was about 110,000 barrels a day better than it was a year ago, just as a result of better reliability and availability. Big drivers there in the UK and Malaysia, but also the Gulf and one or two other countries. So that is a very material uptick.

It is also coming off not the best of quarters a year ago. So that gives you some feel of the volume impact, and of course the margin impact does vary. But it actually more than offset the decline, the underlying decline in the assets that were all across the portfolio.

Now this is just better reliability and in practice, one of the approaches coming out of the improved programs on maintenance is the timing and the scheduling of maintenance turnaround, looking at them in the same way in the upstream as we do in the downstream.

A typical downstream turnaround period is three or four years; typical period in the upstream was a lot shorter than that, in fact one year in many places. Every year there'd be some turnaround for maintenance.

So just taking best practice within the group and improving the way we do the work, working better with contractors, managing their logistics offshore, for example making sure the parts are available when you need them.

These are all hard yarns, but when you're doing them and we're actually managing through a production excellence program in quite a different way across the asset base now, driven by Andy. We've seen that really start to deliver to the bottom line and this was one of our better quarters. No question with that, more than 100,000 barrel a day uptick.

You're absolutely right that taking costs out at the same time, if we are too indiscriminate, creates a risk. Which is why, precisely why we've not stood up before and not really standing up today either and saying we will take $5 billion out of cost.

And what we have said is we have taken or we are taking, not that it's some mature manner we will take $X billion out, because it's that type of statement that creates the risk and exposure when everybody tries to do the right thing, even though they sort of have the concern about the risk you highlight. It is an ever-present risk in our business.

Safety comes first, always has been, always will be. And safety and reliability are very closely correlated. Scrip Dividend, it's a great question. What we have said is priority for cash flow, just a reminder, first of all debt reduction, then dividend, then combination of investments and buybacks. The Scrip is inherently linked to the buybacks.

It's highly unlikely we would start buybacks before switching off the Scrip, but it's also highly unlikely we'd switch off the Scrip and cut the dividend. So we will and must reduce the debt first.

We need, and what I stated before just to be clear, is that we need to see the debt and the credit metrics returning to the point where they support the current ratings and a strong credit rating. The proxy for that was a 20% gearing. So we needed either to be at 20% or line of sight to 20% and below.

And that figure is now probably low 20s because of the point I made earlier about financed leases. So we have to turn the debt around, take the gearing down.

When we get to that point with clear line of sight to how we're going to ensure that the metrics are in a robust place for a credit rating and are not going to slip backwards, then we move to the next set of priorities which in the first instance would be almost certainly stopping the Scrip.

And that isn't, unlikely to happen this year looking at where the oil price is, and one of the big drivers will be where does the oil price go in terms of timing. But the oil price is not the long-term driver. The sequence of events I've just stated and the logic will apply, it just may take longer if the oil price stays lower for much longer.

But some recovery of oil price together with delivery of everything that I probably already talked about in terms of improving the cash flows and reducing the debt should within the next two to three years lead to switching off the Scrip, and at that point considering what we do at buyback.

But these things may be sequential, and therefore we do need to see the gearing down in the low 20s and still trending lower before we have that discussion. Many thanks.

Could I move to the next question, please?.

Our next question comes from Rob West from Redburn. Please go ahead. Your line is open..

Hi, Simon. I'm chomping at the bit to ask questions about your Integrated Gas split out, but I'll keep them high level and save the real nerdy detailed ones.

My main question for you is why can't we have more disclosure, specifically around the things we'd really want to know, like the average realized LNG price, or the cash contribution from Pearl, which is a very unique asset in that portfolio? Can you say what those are? Is there a reason why you specifically can't say what those are? And then my second question is just on the divestment targets.

I think you mentioned $3 billion coming in from Showa Shell, Shell Malaysia, MLPs and Denmark. Can you tell us what is the annual cash generation from those assets? And how do you think about the annual cash flow you'd be willing to divest in that $30 billion divestment target? Thank you..

Thanks, Rob. Disclosure, I appreciate the interest. Unfortunately, I would like to think we're probably as transparent as anybody of our scale and size. If we were a two asset company, then we'd maybe need to be a bit more, give more disclosure around key assets.

Pearl remains one of the most valuable assets in the portfolio, if not the most valuable single asset, but is also a confidential one in terms of the agreements between ourselves and the Qataris.

So it's a very strong cash flow, even in today's oil price environment, because it's essentially it's not production sharing, it's a revenue sharing agreement. But it's been a great cash generator both for Shell and for the Qatari government. The average realized LNG price, I don't have a pushback reason why we're not giving it.

I'll take that one away and think about it. I just know for sure it would be actually quite difficult to calculate at the moment, because we're still working on the systems.

I just mentioned in the press conference this morning that the fact we even have these results at all is the result of an enormous amount of effort by two teams, primarily in Reading and here in The Hague to actually take two sets of accounts and bring them together. So point taken, we'll think about it.

$3 billion asset, well any asset we sell, we're selling the associated cash flow, and that's what's being valued by the purchaser.

It's not easy to explain what you might think of in terms of modeling, but there's probably on average, because we're selling quite a lot of assets, it's what we sell is probably cash flow same return on what we sell it at as the average cash flow on capital employed in service in the business.

And capital employed in service in the business is probably not far short of $200 billion. So yes, we lose cash flow. but it's not that major. And it's probably not that different from the average in the portfolio once you look across.

We are at the stage of relooking I think fundamentally at the cash flow generation characteristics of the assets we've acquired and how they play, not just in terms of the next six months, but the longevity, the risk profile, and which of those assets really formed the part of the strategic intent, the long-term portfolio that we're trying to create.

That is very much the sort of discussion that we'll address under the strategy discussion on June 7. I won't go any further on IG disclosure. But thanks for the question and the suggestion. Next question, please..

Next question comes from Jason Gammel from Jefferies. Please go ahead. Your line is open..

Thanks very much, Simon. I just had a couple questions around Motiva actually. First of all, I was hoping that you could address some of the factors that led you to decide to dissolve that joint venture.

And then second, if I look at the assets that you have elected to retain, it would seem to indicate a preference for gasoline manufacturing capacity and light cracking capacity in preference over diesel manufacturing capacity and being able to crack the heavy barrel. Have I gotten that right? And then finally, I'll take a futile one here.

Do you have an order of magnitude on the amount of cash that you think you might take out of the transaction?.

I'll have to be careful here because some of this is still commercially sensitive and under negotiations for how we finalize the deal. But why dissolve, the original joint venture was 1998 for 20 years.

So there was, I won't call it a pre-nup, but there was an opportunity to look at do we want to continue and do we still have the same sort of level of strategic alignment, the belief that we can create more value together than we can apart. Now yes, we can create value together.

But we said, well if we do split the asset is there a way in which we can allocate where we're both more comfortable that we can manage the value chain. And that's ultimately how it ended up. And yes, we could have taken one or other set of assets. But at the end of the day, a negotiated deal is what people will accept.

And a balancing payment is likely to be made, thus it may be made in terms of taking on debt or otherwise. So you might not see cash actually flow. So the way the assets are structured, that balancing payment per se is clearly going to be ours, not in the other direction. So likelihood is it will contribute to the divestment proceeds.

It just may not show that way in accounting terms. And it is most likely that Motiva will move from being an equity associate, something where we only see cash flows when dividends are paid out. It will move to a fully consolidated basis, but only half or just less than half as much.

Now there will be some changes as of when we conclude the deal, but that's where we have to conclude it, and we'll try to be as transparent, as helpful as we can because it's a big piece of kit and the numbers are non-trivial. And it will impact everything I said about OpEx and CapEx for example. Thank you. Next question, please..

Our next question comes from Aneek Haq from Exane BNP Paribas. Please go ahead. Your line is open..

Thank you. Afternoon, Simon. Just two questions please if I can. One, you talk about the urgency of the debt, and then obviously there's a big focus on simplifying that Upstream portfolio, which if I sort of think about the buckets you laid out, deepwater, Integrated Gas.

I think I might be even a bit light here, but there's at least about 1 million barrels a day which is in some ways sort of noncore.

And I just wondered if there's – or at least why would you not consider a spinoff or an IPO potentially if that sort of becomes the best option in terms of disposals and maybe even get the debt down that way? And then my second question, that $30 billion guidance just in terms of, can you just help me bring that number, capital invested, back to capital expenditures just in terms of the cash flows? It seems as though it's sort of trending around $27 billion, and I just wanted to get that cash flow equivalent number based on that guidance please, if possible..

Thanks, Aneek. I may need to ask you to clarify the second question. The first one, the focus on simplifying the Upstream, why not IPO part of it or otherwise.

Yeah, why not? Well, the primary reason is it's $45 oil, so how attractive would it be in the market? But there are no prima facie reasons why we wouldn't look at such a monetization route, if that were the best way to create value. It's not obvious that in today's market it would be.

But the teams we have looking at monetizing assets are looking at a very wide range of assets that if we were to divest all of them, it would be considerably more than $30 billion dollars coming in. But it's a variety of types of transaction and Motiva being one of them for example, a split. There are other transactions which could involve markets.

We did actually create the MLP, the IPO in the US. So it should be clear that not only we're open to it in innovation and ideas terms, but we are able to deliver such complicated deals and execute over a period of time. So that's very much on the agenda, but all of it is subject to what will the market take at any given point in time.

And just on the second question, I'll try and answer and then see if it's correct. When I talk of $30 billion capital investment, that isn't all cash in any given year.

The two main factors that differ are financed leases, when we bring an FPSO onstream, and exploration expenses which actually pass through the CFFO and not through the capital, the cash used in investing on the cash flow statement.

So $30 billion of capital investment may well indeed translate to something this year around $27 billion of cash used in investing on the cash flow statement.

So indeed, there is a bit more, a bit better free cash flow position than you might otherwise expect, and you can see some of that in Q1 where the capital investment was $6.1 billion but the cash flow in CapEx was somewhat less than that if you look at the cash flow statement.

Did that cover your second question or was there a more specific point to it?.

No. No. that's exactly it. That's perfect. Thank you..

Great. Many thanks. Next question..

Your next question comes from Thijs Berkelder from ABN AMRO. Please go ahead. Your line is open..

Yeah, good afternoon, Henry. Two questions on Integrated Gas and the BG contribution.

Can you maybe tell what the BG contribution is in the Integrated Gas segment? And secondly, looking at especially the production costs in Integrated Gas, can you tell me why they're so much higher than they used to be? Is that only BG for one and a half months?.

First question, about $200 million generated in IG from the BG assets which would include the trading contribution as well. The production costs, I'm not sure I have a response for you to be brutally honest.

The production cost, if I were to think about it would include Queensland, which by definition are relatively high compared to our average, because many of our IG assets are associate companies and we don't show operating expense per se. They're accounted for as associates.

So the operating cost is primarily in Pearl and maybe one or two other operated assets. But it's not showing as high, whereas Queensland Gas a bit as I mentioned earlier, the Upstream bears the cost of the, effectively the total end cost of running through the LNG in the midstream assets. That may be one of the drivers..

But there are no special factors in there?.

Yes. Although, they will persist. So if I'm right, that it is in fact Queensland Gas, that will happen. It's also true, by the way, that our Pearl GTL had a big major shutdown that ran over the quarter. And the plant has just come back online in the last couple of days.

So that major shutdown and also much lower production was also a factor of the back end of the first quarter. Okay, next question, please..

Our next question comes from Asit Sen from CLSA. Please go ahead. Your line is open..

Thanks. Good afternoon, Simon. Two questions, please. So first on Brazil and second on LNG. On Brazil, could you quantify production or current production or production in the quarter since it looks like one FPSO started there, and particularly since Brazil is such an important part of the story.

Any color? And second on LNG, could you explain or help us understand the impact of Sabine Pass LNG exports on Shell's financials since there's a fixed liquefaction charge? The ramp up is expected to be fairly substantial, so I'm wondering if you could help us frame for us the potential impact on a broader Shell portfolio, please..

Thanks, Asit. On Sabine Pass, you're right, it's fixed liquefaction on top of effectively we bought the gas at the Henry Hub and lift. We haven't really lifted much gas yet. It's still early stages. And we've not been the lifter, I believe. So most of the volume I think in that first wave does come our way, but it's not yet had a major impact.

And yes, we will need to ensure that we are able to sell the gas to cover the liquefaction costs. The good news is, in our view, that's the lowest cost LNG that is available from the North American content, including all the other projects that so far passed FID, which is a good place to be in.

The fact that Henry Hub is lower also makes it potentially attractive to take the gas over to either into Latin America or to Europe. Brazil production, absolutely right, major factor. We're running around 200,000 barrels a day Shell share at the moment in Brazil, of which our own sort of legacy is around about 30,000.

The BG contribution around 175,000 barrels a day. It is ramping up all the time. So we're seeing great well performance, up to it could be 40,000 barrels a day on some of the wells if we opened up completely. And that's one of the reasons that we're seeing lower costs than we had originally envisioned.

Two further FPSOs will come on stream this year, so we should have nine up and running by the end of the year. So we should just see a little bit more every quarter for quite some time to come. There are actually 16 FPSOs in progress. And I think the last one comes on in 2019.

So, so far so good, and the actual ongoing production, the decline rates on some of the wells, some of the reservoirs, very low. And it's still very early days to be talking about impact on resource and ultimate recovery. Many thanks. Next question, please..

Our next question comes from Jason Kenney from Santander. Please go ahead. Your line is open..

Hi, Simon, and thanks for your time with questions today.

I just wanted to go back to cash flow as well, and here I'm looking at the medium term sensitivity guidance, which I think in the past you have said would have been around $3 billion to $4 billion for every $10 per barrel shift over the next couple of years, maybe moving towards $4 billion to $5 billion 2018 onwards.

Now I was looking at some of the consensus estimates when the Vara Research guys pulled together the annual numbers and compared that to the oil price estimates that we use to drive that consensus.

And I mean the average analyst there has got some sort of $7 billion shift for every $10 per barrel in the next few years, which is potentially over-egging the cash flow.

But I mean is that a possibility? Or is it something I should be ignoring?.

At $7 billion I think you should ignore, Jason. The production that we see going forward needs some growth before we get to the $5 billion of earnings and cash flow for every $10 sensitivity this year. It's probably closer to $4 billion than $5 billion as we ramp up.

But as I noted earlier, effectively the new BG production is highly price sensitive, and most of it is directly price sensitive in Brazil, Australia, Kazakhstan, UK, Trinidad. Those are the primary countries that we're adding, and of course, our own new production is in the Gulf, in Australia, also in Kazakhstan.

Therefore, basically every barrel brings some kind of price exposure with it. So we are becoming certainly more price sensitive as we go forward, but it'll be really 2017, 2018 before we hit the full $5 billion sensitivity. But we don't have any scenarios that I've seen where it goes above $5 billion..

Okay. I believe no more questions or that's the end of the call. We're at the end of the time. So what I'd like to say, many thanks for your questions and for joining the call today, to everybody. Reiterate again the Capital Markets Day, London, Tuesday, June 7. Everybody on the call hopefully will be able to join us.

I will be joined by Ben and by most of the executive team. Great chance for you to hear a bit more about strategy, intent, some of the opportunities, some of the challenges that we face.

So very much look forward to talking with you all then, and between now and then please feel free to connect with the IR team and help with your own modeling, because I think it's in everybody's interests that we all understand this better quickly so that as we go into Q2 and Q3, we're all sort of working to the same expectations.

So thank you very much. Have a great day. Take care..

Thank you for your participation, ladies and gentlemen. That will conclude today's conference call. You may now disconnect..