殼牌 (SHEL) 2016 Q1 法說會逐字稿

Welcome to the Royal Dutch Shell 2016 Q1 results announcements.

(Operator Instructions)

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 of 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 make.

Let me give you a summary, and then of course there will 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 differentiator us with our downstream and integrated gas businesses delivering good results, underpinning our financial performance, despite the continued low oil and gas prices of $34 average Brent for the quarter.

We delivered $1.6 billion of underlying current cost of supply, or CCS earnings, (technical difficulties) $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 opportunity to do exactly this in the down cycle.

It's early days, but we are extremely pleased with what we're seeing so far from the acquisition.

Turning to the results, and I will start with the macro, we have seen a sharp decline in oil and gas prices compared to the year ago, reflecting primarily the OPEC's policy change.

Brent's oil prices were some 37% lower than year-ago levels; similar declines in WTI and the other crude markets.

The realized gas prices was 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 to 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 at the same quarter last year, and was driven by the further reduction in naptha 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 prices.

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 the subset, and in more detail than in the past.

In downstream we have given an earnings split formally for the 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 noisier over the past couple of years in terms of quarterly impact.

We're now treating non-cash foreign currency impacts in Australia and Brazil, specifically on the deferred tax assets, we're now treating them as identified items.

You will see a restatement of that in the result tables today, both explicitly and also implicitly in the businesses.

As this effect was large and 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 is a 63% decrease in earnings per share from the first quarter last year.

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 movements.

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

Turning to the business segments in a little more detail.

Upstream earnings excluding identified items for 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, and that is a $1.4 billion affect compared to a year ago.

However, I think it is 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 column.

Turning now to integrated gas, earnings there were $1 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 oil equivalent per day, 16% higher than the first quarter last year.

The uplift from the BG acquisition accounts for the majority of that increase.

Let me also note we're seeing benefits of Shell's actions to improve the uptime.

Less maintenance than a year ago, better reliability in uptime, for example in the UK and in Malaysia, all good to see.

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 of the same level as last year in fact, driven by high unit and lower cost.

Chemicals earnings were 8% lower than a year ago.

That was due to the lower margin in the US base chemicals, [both] in the margin [XM] margin and the downtime, again at the Bukom refinery in Singapore.

This was partially offset by lower costs and the recovery of production at the Moerdijk site in the Netherlands.

Overall another a good quarter for the downstream.

Return on average capital on a clean CCS basis was 18.8% at the end of the quarter on a 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 are dividing the refining and the marketing assets portfolio between us.

We've 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 to complete the Showa Shell investments 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 is a 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 is pretty close to today's spot.

Cash portion of the BG deal was $19 billion.

That resulted in 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.

Gearings: at the end of the quarter was 26.1%.

We had recognized certain operating leases from BG as finance leases.

These include FBSOs, some of the shipping vessels and some -- one LNG facility.

Overall the BG deal added some 9% -- 9 percentage points to our gearing and 2 percentage points of that is as a result of effectively the finance 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.

More specifically on the BG consolidation some quite significant one-off impacts.

The final transaction price for the BG acquisition was $54 billion, or GBP37 billion.

You will find details of the accounting impacts from BG in the results announcement, but the headlines: Goodwill was $9 billion, and this is an accounting definition, an 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.

Under the accounting standards, fair value is calculated using forward price curves as at the date of completion for the first two years and then analysts' macro forecast thereafter.

So just a reminder, the oil price on the February 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 profits and loss account going forward will include annually a $1.2 billion after-tax depreciation charge for the purchase price premium.

That is basically $100 million a month.

So we have 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 Market Day we're having in London on June 7. However, it is 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 oil equivalent a day in the first quarter.

That is 25% higher than the year ago, and it is a third higher than the production that was in the public domain when we negotiated and announced the bid.

The production in 2014 was 600,000 barrels a day.

In the first quarter gains for Shell per share we booked only two-thirds of this amount, 522,000 barrels a day oil equivalent to be precise, and (inaudible) 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 non-operated 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 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 that the lower than expected implementation costs.

Overall, great start with 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 a capital investment guidance for 2016, a $33 billion potential to reduce that figure further because of course we haven't actually gotten under the hood of the BG portfolio at that point.

The capital investment for 2016, this is the actual results, is clearly trending towards $30 billion.

We look at detail of 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 out of 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.

This $30 billion figure is 35% below that level.

It includes -- it actually includes well over a billion of non-cash items for finance 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 cost is trending downwards to a run rate of around $40 billion by the end of the year.

And during the year we will take a few one-offs costs most likely associated with the transaction, which is why we do not give a full-year figure.

That $40 billion, compares again, go back to 2014 with some $52 billion, $53 billion, 20% lower that the 2014 combined level.

In simple terms we're saying all through last year judge us on what we, not what we say we're going to do.

We are effectively taking $17 billion out of the CapEx and $13 billion out of the OpEx, $30 billion out of the spend between 2014 and 2016.

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.

That is 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.

Just to summarize again then, integrated activities wellhead through the customer, do differentiate those.

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 are 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 opportunity there in the down cycle.

Early days, very pleased with what we're seeing so far from the acquisition.

With that lets take your questions.

I sort of raised it earlier, but I do acknowledge for all of you, we have changed some of the reporting segmentation and this may be making some of the modeling quite difficult.

Can I suggest that we do not cover those on the call and that we can follow up with the IR team primarily?

I will do what I can to help, but it may be a distraction for the main points in the call.

I will also remind you, have the Capital Markets Day in London on June 7, when hopefully everybody on the call will be able to join us.

(Caller Instructions)

Operator, please could you poll for questions?

Thanks.

(Operator Instructions)

Oswald Clint, Bernstein.

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.

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 into the black?

Is that going to be sufficient for 2Q?

Or maybe if you could talk about further cost reduction across the geographies.

Second question, on the CapEx trending towards $30 billion.

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?

Will be above that?

Is there a chance it could fall below that?

Just a bit more clarity around the CapEx number, please.

Thank you.

The primary driver of the upstream number is the $34 oil price plus the fact that even where we're producing gas there is a linkage to the oil price, with some lag in some cases.

That fundamentally is the difference.

But today's oil 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, it costs.

We have made clear today, the organization some time ago, and we're seeing the bottom-line results coming [down] but in thinking about costs, the combination of BG and the $40 world.

It's a fantastic opportunity to take our [revenue], as long as you think about the cost -- the price being low forever, and ensuring that cost don't come back again when they go back up.

Very strong focus on cost.

That will come through.

It's difficult to do $1 billion in the 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 have been looking very closely at some of the more difficult areas, should we say, in costs such as the North Sea, and therefore working hard in that.

As we go forward you're going to see some new production coming on in places like Gorgon and all of that, in integrated gas, of course.

And then in Kazakhstan and in Stones and in the deepwater.

And we will see the BG synergies kick in, although quite a lot of that in the first year is on lower levels of exploration.

All of those things contribute, and each in their own small way.

The bigger short-term factor is clearly the oil price.

That trending towards $30, 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 - or the planning for integrations.

So we did have a reasonable view about what some of the choices are.

The actual CapEx in quarter one was $6.5 billion.

That is rounded up to include the January spend in BG.

Multiply that by for four, you come up with a number less than $30 billion.

If you look at the 12-month number, it's slightly above $30 billion if you include BG.

We're heading directly for $30 billion, and we're making basically decisions as we go along at the margin.

I would expect we will hit $30 billion or below as we go through for the total for the year, because that is what the trend is telling us.

And we were finalizing that, really, over the next month or so ahead of the Capital Markets Day.

If there is an issue around rig commitments, then the potentially idle rigs and what we choose to do with them have some noise impact.

It could bear on OpEx, it could bear on expense, it could bear in CapEx, which is why I'm slightly reluctant to commit to a very specific number.

It will get to $30 billion or there abouts I think.

90% is already committed.

So hopefully that helps, Oswald.

That longer chance, but I think it's a question that quite a lot of people will be looking to hear the answer to.

Lydia Rainforth, Barclays.

Two questions, if I could.

The first one, and I come back to focus on the OpEx side.

If I look at the chart that you show, based on 2015, 2016 seems to imply about $8 billion reduction.

Which is clearly more than the $3 billion standalone guidance for Shell cost reductions on the $2 billion synergies.

Is that the right way of looking at it?

That you are 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 get to what you think is now the cash flow break-evens because the CapEx and dividends, and since the oil price [ought to be it] for this year or next year?

Thanks.

The reduction between 2015 and 2016 that we're seeing, effectively you're using a ruler there.

It's not necessarily $8 billion because we're trending towards a run rate of 2014.

So we might end up with slightly more than 2014 for the year because of one-off items in the first part of the year.

But broadly speaking it is $47 billion to a run rate of $40 billion in the year.

And yes, we're seeing more opportunity than we had originally expected.

And we previously stated $38 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 planned for or expected.

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

That has 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, but $100 million -- say a few $100 million net.

Quite a few ongoing initiatives which are continuing.

And they took cost out last year and they're taking more out this year.

It is aggregation of the contributions from many people, the [90,000] (technical difficulty) [in Shell] are 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 is very much the direction we will head.

Is that cover everything Lydia?

Christopher Kuplent, BofA Merrill Lynch.

Simon, two quick ones.

I wanted to check.

I think you have now got almost $70 billion under your definition of financial net debt.

The free cash flow obviously still negative in Q1.

I guess will remain negative this year.

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.

Secondly, just wanted to get my hands 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.

I will try on the second one.

The first one is the really important point.

$69 billion of net debt.

Yes, it is something that I am -- 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 to $4 billion.

$15 billion of that, that impacts the free cash flow.

The $34 oil price didn't help either.

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 the $45 -- what brings it down?

It is the continued reduction in OpEx, it's the continued reduction in investment level.

And importantly it's the coming on stream with new projects.

None of these are easy fixes.

I am 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 the BG synergies coming in as we [speak].

The gearing figure of 26.1% is a couple of percentage points higher than previous advice, and is driven entirely by the treatment of the leases, the financial leases, rather than operating leases.

And this has 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 to have to add 2 percentage points onto any previous statement of expectation, and that [figure grows] has the impact of going forward by new FPSOs as well.

A manageable situation, but not ones that has an easy fixes.

But I think all the right things are being done.

The credit rating agencies have taken a close look and [what it did] is brought most of the industry down.

We came down to AA with Moody's.

S&P we are at an A-plus rating at the moment, and that is -- that still with a negative outlook.

So we're looking at effectively 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 to get those metrics back into the right place.

Our $40 billion OpEx, here's the high level breakdown.

It is half-and-half upstream/downstream.

[$1] billion or so is in the downstream and the $20 billion upstream 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 cost, 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 where we do the work.

Different relationships with, for example, suppliers, not just on unit rates but fundamentally changing the way we deal with standardized design, different way of handling IT, et cetera.

It is not something we started three months ago.

It is something we started three to five years ago, depending on the area we are looking at.

Therefore we're pretty confident most of what we do will stay [active] if the oil price does recover at some point in the future.

Clearly at the margin where we are in the third-party services are big supply to us, but there is exposure if fuel price comes back.

But to be honest, a lot of the savings that we have seen so far have been in, for example, areas like drilling.

It's been better performance as much as it has been low unit rates.

Or it has been in areas of activity such as the North Sea where reducing cost is not a 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 of oil price go back up.

We're quite pleased with what we have been seeing so far, and let's see how much further there is to go.

Many thanks, Chris.

Hopefully again both questions quite relevant to most of the audience.

Next question, please?

Jon Rigby, UBS.

Two questions.

Just ask a question on LNG.

I think you said there's about a $200 million contribution from BG.

So can you confirm or discuss a little more about what you're seeing in terms of optimizing cargoes?

Are you able to see the kind of trading and optimization and earnings that BG was able to generate?

And is that starting to spread into the Shell business as well, the bigger Shell business?

And maybe some color around that would be really useful.

Secondly, 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 would expect it to be, all things equal?

And maybe are you able to calculate or indicate what you think the delta might be if everything was running rather more smoothly?

Thanks.

Thanks Jon.

You are right on chemicals.

I'll say that first.

It is $200 million, $300 million.

It's because 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 left on the table compared to everything running smoothly.

LNG optimization.

Still a bit early days.

I don't want say to much, but some commercial sensitivity here.

But I think we're seeing just as much flexibility and optimization in the Shell portfolio as there is in the BG portfolio.

It is a great opportunity to learn from both sides how to optimize not just in the short term but the medium to 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 the market, work backwards to supply, and vice-a-versa.

As the two meet in the middle, 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.

Having Steve there plus the guys who worked on our portfolio is indeed identifying further opportunities.

But certainly in the short term, interestingly the optimization is just as positive from the Shell portfolio as BG.

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 is a great point for the future -- opportunity for the future.

I would just say there's opportunity to note.

We've now got two volumes in for LNG, which are effectively the share of equity production which is about 7 million tonnes in the quarter.

You're looking at over 30 million tonnes on an annualized basis.

And we have also churned the Shell share of effectively the sales, because in BG's portfolio and increasing in Shell portfolio we're listing other people's production and selling it.

Our share of sales cells 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] molecules.

It gives you a feel of the scale and the opportunity.

Thanks Jon, and good luck against Brighton on Saturday.

Next question.

Biraj Borkhataria, RBC.

I had a couple.

The first one in looking at upstream Americas, or North America, now that it's stated.

CapEx was down quite sharply Q on Q by about $1 billion.

I was wondering if you would talk about the unconventionals business specifically and 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.

The second question was more of a clarification, really.

I noticed the Oceana 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 is going on there.

Thanks.

The unconventional business in North America and Argentina together is getting about $2 billion of capital allocation this year.

That is quite a lockdown on previous year.

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.

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 is a bit in a holding pattern.

Strategically we're in a good place.

We have got in there in terms of resource potential, you're talking up to 12 billion barrels oil equivalent resource potential across Canada, United States and Argentina.

Around 75% or 70% or so of that is gas and we have the balance sheet value is just under $15 billion.

So you have got massive resource, just over $1 a barrel.

I think over time this is going to be a great value to develop.

But in the short and the medium term it will be on there pretty much on [carry or] maintain capital allocation.

The Oceanic gas realization, and ultimately this is driven in part because what you see is a netback.

So it is a netback both in Queensland and in Western Australia.

And therefore the realization -- a netback for the LNG price fits almost directly to the LNG price.

Once you deduct the -- effectively the way Queensland gas has been structured with total-in agreements and pipeline totaling.

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 is just the nature of the BG set-up in Queensland.

But it is also not dissimilar in Western Australia, at least in terms of the realization that we would recognize.

Irene Himona, SG.

My first question is on volumes, if I may.

You have 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?

Secondly, going back to the $40 billion.

Effectively you are talking about faster nearer-term OpEx reductions, as I understand it.

How does that relate to the $3.5 billion synergies from BG by 2018?

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 audited?

Thank you.

Volumes, if we had three months of BG rather than two months we'd have been about 3.95 million barrels of oil equivalent a day.

So quite a step up.

And as we go forward, I cannot give you guidance, simply because it literally is not on my radar screen, the production, because we are spending all the time on the cash.

What are we spending, what are we earning, and where are the priorities?

Production, to be brutally honest, apart 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.

I do think fundamentally at the moment we're putting together the asset-level detail, the maintenance and the underlying spend programs.

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.

I cannot give further guidance on the volumes.

The $40 billion as it relates to the $3.5 billion.

Well, the $3.5 billion by 2018 was, if you will recall, $1.5 billion of exploration and $2 billion of OpEx.

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 is a bit harder to work, but actually we're finding we're doing that much more quickly.

I cannot say -- again don't actually have the exact figures, but a lot more than they originally expected when we did the perspectives will be delivered this year, and it will also cost us less.

We have said in the perspective 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 does not 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 is something we'll probably revisited in a month or so as time for Capital Market 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 plan but also the psychology behind them.

How optimistic or conservative are they, and how are they comparing with what is actually being delivered.

The actual asset performance is extremely good against the original BG plan to date, I must say.

Therefore that might actually throw off, yes, there are some value synergies that we can bank earlier rather than later.

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 definition the two most valuable assets in the portfolio.

So far, so good.

But I cannot be more specific than that.

I'm sorry.

Next question, please.

Martijn Rats, Morgan Stanley.

I wanted to ask you two things.

I listened to part of the media call this morning.

And in there you sort of evoked a spirit of Mario Draghi by saying, we will do whatever it takes to balance our financial framework over the cycle.

I was wondering if you could elaborate on that?

It's sounded like you potentially had something specific in mind.

And also how far does the balance sheet gearing need to rise before whatever it takes really kicks in?

The second question I wanted to ask is with regards to operating cash flow in the quarter.

Even taking into account lower oil prices, the $4.6 billion ex working capital looked a little light.

And I was wondering if some of the one-off costs related to the acquisition, some of the $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?

What I actually said this morning was in response to a question, so what is your break-even price in cash terms?

And so far this afternoon you have all been kind enough not to ask the same question, as you probably would've 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 quote somebody else.

Unfortunately, it is through the cycle.

The aim is not to achieve any given break-even point in any given year.

So I also quote as going backwards to the previous 12 months is [$61 billion] to 12 months of 2015, break-even was [$55 billion], or around [$70 billion] excluding divestments.

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.

That is one we can control, the other we can't.

But after that it is investments in OpEx.

And we 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.

That is clearly stated by the rating agencies.

We need to start to reduce the debt.

That the simple -- that is priority number one.

We are in that situation now.

$4.6 billion of working capital looks a little weak was the premise.

The [AES] perhaps.

Yes, it is got some one-offs and it's got, example, the [$70] (technical difficulty) and -- paying for the deal.

The present $300 million or so to [George Osborne].

In terms of the cost of deal, but that is less than $0.5 billion in terms of the quarter in cash terms.

And there are -- there is 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-offs 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 affect 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.

Those things will play through.

And it's always difficult to look at one quarter alone to see (technical difficulties).

Let's see how that goes going forward.

Thomas Adolff, Credit Suisse.

Two questions as well, please.

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 guidance amongst the super-majors.

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 [stated and no further] cost reduction to come outside of Shell.

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 is the XTO-type management or whether it is the BP-type management which is truly independent.

Have you figured it out yet?

Thank you.

Still have words with Marvin.

On CapEx, is $30 billion the right number in the current price environment?

Probably not.

Let's look where we're coming from.

We started at $47 billion two years ago.

That is massive reductions.

But even at what we spent today some of that was committed in an oil price environment a lot higher than today.

So the unit rate of completed projects, think of Gorgon, [Prelude ], Stones, et cetera, [Kazakhstan, Galleon].

Those costs reflect a higher oil price environment, not today's oil price environment.

The -- to stay in business and maybe invest a little bit for the health, the long-term health of the business, is probably lower than $30 billion at today's unit rate, the cost that we would expect to see.

Again, no specifics.

It is just less than $30 billion is what I would say.

Could be several billion dollars less.

On the lower 48, there certainly are two models there.

The reverse integration into an XPO-type model or the UDI 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 cost 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 basically the above-asset costs.

And how we deal with that will determine the answer to your question.

It is coming down.

It is coming down across the board, part of the $40 billion.

It is 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 costs are feasible for the shale business then it should be feasible everywhere else in shale.

Let's use that as the pilot to identify where we can go further, faster elsewhere.

Both of those are in progress at the moment.

I think Andy will be with us on the Capital Market Day.

I don't know.

He was in the US last week.

So a good question to ask him.

Alastair Syme, Citi.

Two quick questions.

One on OpEx.

You give the 2014 reference pro forma.

Can you give the 2015 by any chance?

Secondly, appreciate the integrated gas and upstream from an accounting standpoint.

But does that distinction imply wholly internally?

I know Martin and Andy are running the business.

But our people allocated to these different businesses distinctly?

On the latter, yes.

They are being basically running as separate businesses.

We had, although we reported externally an IG segment which was basically the same assets previously, that the reporting lines were not unified, to say so.

Martin is now directly accountable for activities such as Trinidad and Peru and all of the trading that is done through Steve, Steve Hill in Singapore.

That is effectively how that works.

On the OpEx.

2015 pro forma, it was basically interpolate between the two.

It's somewhere around $46 billion, give or take.

The reason I'm not citing more specific is there are some difference in definitions and accounting treatment.

It is 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 improvements that come thereafter as well.

Lucas Herrmann, Deutsche Bank.

By the way, thanks for the added disclosure, which is useful even though it will require a lot more spreadsheeting.

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, on cash flow.

Deferred tax and other provisions, and this is not the deferred tax adjustment you have been making quarterly but the deferred tax negative that has been running through your cash flow statement.

Can you talk through that in a little more detail?

The number has become increasingly large, and just sits there as a big negative with no real explanation.

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.

Both the same problem, by the way.

The are 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 of Gulf of Mexico.

Those are the big four greenfield over which we could take a final investment division in the next, well, less than 12 months.

It is highly unlikely that more than -- I would say to you, maybe only one, that we'll actually go ahead in that timeframe.

And basically it is a choice of whether -- what is the best way of retaining or maximizing value from that set of opportunities?

And the chemicals plant is probably the first one because of the timing of certain commitments.

But they're already in place.

It is 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 smaller ones as well.

We have had quite a lot of discussion, not yet pulled the trigger on it one way or the other.

It is not a free option, of course.

There are costs of keeping the option open.

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.

Effectively the tax benefits 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.

It is 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 since they're on the balance sheet, they are assumed to be.

The deferred tax liabilities will play out over time as the earnings come through from the assets to which they are associated.

Which the step-up of $6 billion that I just mentioned, virtually all in Brazil.

Therefore you can -- [I'm elated to see] Brazil produce and perform, that you will see the liability reduce.

Deepwater production.

I'm just looking.

Is around 400,000 barrels a day at the moment, which basically is the combination Brazil, US, Nigeria.

That would be the Shell [moving] on BG.

BG was running -- is approaching now 200,000 barrels a day effectively in Brazil.

You are seeing over 0.5 million barrels a day.

It is 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.

It is probably the most price-sensitive element within the upstream business.

And therefore -- and it's also piece that is growing.

So it's the big driver of the future, but it is not helping today.

I think that is probably as much as I can say on that.

Probably something we'll need to follow up as we do the Capital Markets Day.

Anish Kapadia, TPH.

A couple of questions for me as well, please.

Just following up on a couple of things.

The first thing one was on cash flow.

Looking at Q1, if we take the cash flow from ops, export and capital and post-interest, it seems like about $4 billion.

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

Is that a good basis to estimate cash flow for this year, using your sensitivities, or are there any other incremental factors, incremental cash flow that we should think of for the remainder of this year?

The second one on taxes 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 of BG's key profit centers such as Brazil and Australia?

The simple answer on the second one is yes, but I cannot go into to much further detail about that.

We need to be both clear about the best way of doing it and making sure that it is 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 am aware of.

The cash flow estimate for the year, will four times Q1 suffice?

Yes and no.

It is not any one-off factors -- minor quarter one factors get multiplied by four, positive or negative.

So it is not the best way to look at it.

Maybe look at the full year, four quarters going backwards, which were actually an average I think of $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 is just a little help in 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 working capital outflow.

At the end of the day we work on the levers that we can, such as inventory level and OpEx, and then the actual number to an extent will be an outcome.

Guy Baber, Simmons.

Simon, a couple from me.

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 am curious, in an environment where you are attempting to reduce spending and take out costs, 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?

Secondly, in balancing the cash inflows and outflows you mentioned spending, costs and divestments.

You did not mention the Scrip dividend.

So wanted to get latest thoughts and comments around the extension of that Scrip program into 2017 or beyond.

And what your most recent thoughts are around that program.

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.

Our big drivers there in the UK and Malaysia, but also the Gulf and one or two other countries.

That is a very material uptick.

It is also coming off not the best of quarters a year ago.

That gives you some feel of the volume impact, and of course the margin impact does vary.

But it actually more than offsets the decline, the underlying decline in the assets overall across the portfolio.

This is just better reliability.

In practice one of the approaches coming out of the improved programs or maintenance is the timing and the scheduling of maintenance turnaround, and looking at them in the same way in the upstream as we do the downstream.

A typical downstream turnaround period is three or four years.

A 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.

Just taking best practice within the group and improving the way we do the work, working better with contractors, managing the 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 were actually managing through a production excellence program in quite a different way across the asset base now driven by Andy, we have 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 cost out at the same time, if we are too indiscriminate, creates a risk.

Which is why, precisely why we have not stood up before, and not really standing up today either and saying, we will take $5 billion out of cost.

What we have said is we have taken, or we are taking, not in matter or [manner] that we will take X billion dollars out, because it's that type of statement that creates the risk in 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 done, always will do.

And safety and reliability are very closely correlated.

Scrip dividend.

It's great question.

What we have said is, priority for cash flow, just a reminder.

First of all, debt reduction.

Then dividend, then combination of investment and buyback.

The Scrip is inherently linked to the buybacks.

It is highly unlikely we would start buybacks before switching off the Scrip.

But it is also highly unlikely we'd switch off the Scrip and cut the dividend.

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 it either to be at 20% or line of sight to 20% and below.

And that figure is now probably low 20%s because of the points I made earlier about finance leases.

So we have to turn the debt around, take the gearing down.

When we get to that point with clear line of sight of how we're going to ensure that the metrics are in a robust place for 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.

That is 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.

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.

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 buybacks.

But these things may be sequential.

Therefore, we do need to see the gearing down in the low 20%s and still trending lower before we have that discussion.

Rob West, Redburn.

I am chomping at the bit to ask questions about your integrated gas split out.

But I will keep them high level and save the really nerdy details for once.

My main question for you is, why can't we have more disclosures, specifically around the things we would 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 cannot say what those are?

Then, my second question is 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 would be willing to divest in that $30 billion investment target?

Thank you.

The 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 than we maybe need to be a bit more -- give more disclosure in key asset.

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.

It is a very strong cash flow, even in today's oil price environment because it is essentially -- it's not production sharing.

It is a revenue share agreement.

But it has been a great cash generator, both for Shell and for the Qatari government.

The average realized LNG price, I do not have a push-back reason why we're not giving it.

I will take that one away and I think about it.

I just know for sure it'll be actually quite difficult to calculate at the moment because we're still working on the systems.

I did mention in the press conference this morning that the fact we even have these results at all is the result of an enormous amount of asset by two teams, primarily in Redding and here in the Hague to actually take two sets of accounts and bring them together.

Point taken -- we will think about it.

$3 billion asset -- any asset we sell, we're selling the associated cash flow.

And that is what has been valued by the purchaser.

It's not easy to explain what you might think of in terms of modeling, but there is 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 as the average cash flow on capital employed in service in the business.

Capital employed in service in the business is probably not far short of $200 billion.

Yes, we lose cash flow, but it is not that major.

And it is probably not that different from the average in the portfolio once you look across.

We are -- the stage of really looking, I think, fundamentally the cash flow generation characteristics of the assets we have 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 form the parts of the strategic intent, the long-term portfolio that we're trying to create, the value's very much the sort of discussion that we will 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.

Jason Gammel, Jefferies.

I just had a couple of 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?

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?

Finally, I will take a futile one here.

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

Have to be careful here because some of this is still commercially sensitive and under negotiation as to how we finalize the deal.

But why dissolve?

The original joint venture was 1998 for 20 years.

So 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 level of strategic alignment and believe that we can create more value together that we can apart.

Yes, we can create great value together.

But we said, if we do split the assets, is there a way which we can allocate them where we're both more comfortable that we can manage the value chain?

And that is ultimately how it ended up.

And yes, we could have taken one or other sets of assets.

But at the end of the day a negotiated deal is what people will accept.

A balancing payment is likely to be made.

But it maybe made in terms of taking on debt or otherwise.

So you might not see cash actually flow.

The way the assets are structured, that balancing payment per se is clearly going to be us, 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'll move to a fully consolidated basis, but only half or just less than half as much.

So there will be some changes as and when we conclude the deal.

But first of all, we have to conclude it.

And we will try and be as transparent and helpful as we can, because it is a big piece of kit.

And the numbers are nontrivial.

And it will impact everything I have said about OpEx and CapEx, for example.

Aneek Haq, Exane BNP Paribas.

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 think about the buckets you laid out, Deepwater, integrated gas,

I think I might even be a bit light here.

But there's only about 1 million barrels a day, which is in some ways non-core.

And I just wondered if there's a -- or at least why would you not consider a spinoff or an IPO potentially, if that's sort of -- becomes the best option in terms of disposals, and maybe even get the debt down that way?

My second question.

That $30 billion guidance, just in terms of -- can you just help me bring that number, capital invested back to capital expenditure in terms of the cash flows?

It seems as though it is trending around $27 billion.

I just wanted to get that cash flow equivalent number based on that guidance, please, if possible?

I need to you to clarify the second question.

The first one, the focus on simplifying the upstream.

Why not IPO part of it or otherwise?

Yes, why not?

The primary reason is it is $45 oil.

So how attractive would it be the market?

But there are no [prima facia] reasons why we wouldn't look at such a monetization route if that were the best way to create value.

It is 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 north of $30 billion coming in.

But it is a variety of types of transaction.

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 are we open to it in innovation and idea terms, but we are able to deliver such complicated deals and execute over a period of time.

That is very much on the agenda.

But all of it is subject to what will the market take at any given point in time.

Just on the second question, I will try to answer and then see if it is 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 finance leases when we bring an FPSO onstream and expiration expenses, which actually patch through the CFFO and not through the capital -- the cash used in investing on the cash flow statement.

$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.

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 and CapEx was somewhat less than that if you look at the cash flow statement.

Does that cover your second question, or was there more specific point to that?

No, no.

That's perfect.

Thank you.

[Clyde Sparkhelder], Abn Amro.

Two questions on the 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 cost in integrated gas.

Can you tell me why they are so much higher than they used to be?

Is that only BG for 1.5 months?

First question.

About $200 million generated in IG from the BG assets, which would include the trade-in contribution as well.

The production cost, 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 in associates.

The operating cost is primarily in Pearl and maybe one or two other operated assets.

But it is not shown as high, whereas Queensland gas, a bit as I mentioned earlier, the upstream bears the cost of the -- effectively the total-in cost of running through the LNG and midstream assets.

So that maybe one of the drivers.

But there are no special factors in there?

Yes, although they will persist.

If I am right, that it is in fact Queensland gas.

That will happen.

It is also true, by the way, that our Pearl GTL had a big, major shutdown that ran over the quarter.

And in the plant has just come back online in the last couple of days.

That major shutdown and also much lower production was also a factor at the back end of the first quarter.

Asit Sen, CLSA.

Two questions, please.

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].

So it started there, but you listed Brazil as such an important part of the story.

Any color?

Second on LNG.

Could you explain or help us understand the impact of Sabine Pass LNG exports on Shell's financial, since there's sensors a fixed liquification charge?

So ramp-up is expected to be fairly substantial.

So wondering if you could help us -- frame for us the potential impact on a broader Shell portfolio, please?

On Sabine Pass, you are right.

It's is fixed liquification on top of effectively we put the gas in Henry Hub and lift.

And we haven't really is lifted much gas yet.

It is still early stages.

And we have not been the lifter, I believe.

Most of the volume I think in that first [rate] does come our way.

But it has not yet had a major impact.

And yes, we will need to ensure that we are able to sell the gas to cover the liquification cost.

The good news is, in our view that is the lowest cost LNG that is available from the North American content, including all the other projects that so far have passed FID, which is a good place to be in.

The fact that Henry Hub is low is also -- makes it potentially attractive to take the gas over to -- either to 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 legacy is a roundabout 30,000 barrels.

The BG contribution around 175,000 barrels a day.

It is ramping up all the time.

So we have seen great well performance, up -- it'll be 40,000 barrels a day on some of wells if we open up completely.

That is one of the reasons that we're seeing lower costs than we had originally envisioned.

Two further FPSOs to come onstream this year.

So we should have nine up and running by the end of the year.

We should 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 far, so good.

And the actual ongoing production, the decline rates in some of the walls, some of the reservoirs, very low.

But it's still very early days to be talking about impact on resource and ultimate recovery.

Jason Kenney, Santander.

I just wanted to go back to cash flow as well.

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 years, maybe moving towards $45 billion 2018 onwards.

Now, I was looking at some of the consensus estimates when the VARO Research guys pull together the annual numbers and comparing that to the oil price estimates that we use to drive that consensus.

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

But 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 is probably closer to $4 billion than $5 billion as we ramp up.

As I noted earlier, the -- effectively the new BG production is highly price-sensitive.

Most of it is directly price-sensitive in Brazil, Australia, Kazakhstan, UK, Trinidad.

Those are the primary countries that we are adding.

And of course our own new production is in the Gulf and 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 2017, 2018 before we hit the full $5 billion sensitivity.

We don't have any scenarios that I've seen where it goes above $5 billion.

I believe no more questions.

Or that's the end of the call.

We're at the end of the time.

What I would like to do is say, many thanks for your questions and for joining the call today to everybody.

Reiterate again, the Capital Market Day, London, Tuesday, June 7. Everybody on the call hopefully will be able to join us.

I'll 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.

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 is in everybody's interest that we are all understand this better quickly so that as we go into Q2 and Q3 we're all working to the same expectations.

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.