殼牌 (SHEL) 2016 Q3 法說會逐字稿

Welcome to the Royal Dutch Shell 2016 Q3 results announcement. There will be a presentation followed by a Q&A session. (Operator Instructions) I would like to introduce the first speaker, Mr. Ben van Beurden.

Thank you very much operator. Sorry to disappoint you audience, it's Simon Henry, CFO. Ben is not with us today. So ladies and gentlemen, welcome to today's presentation where we've announced our third quarter results this morning. Hopefully, you've had a chance to review and I'll begin with a summary and of course, there will be plenty of time for questions.

I am also joined, I should note now by Maarten Wetselaar, Director of Integrated Gas and new energies. Maarten will join for the Q&A session. We have a prompter slide for you, [prompt you] a few questions. We'd thought it be useful if business directors join me on these calls from time to time. So before we start, just let me highlight the disclaimer statement. Shell delivered better results this quarter reflecting strong underlying operational and cost performance, but lower oil prices continue to be a significant challenge across the business and the outlook does remain uncertain. We delivered some $3 billion of underlying CCS (current cost of supply) earnings in the quarter, $7 billion over the last 12 months.

The integration of Shell and BG is now essentially done. It's been completed well ahead of plan. It's worth a reminder, it's essentially 19 months since we announced this deal. We spent 10 months completing it, 40 major regulatory approvals, no value given away, nine months on integration, all the value now embedded in plans. The integration is proving a very important catalyst now though as we make significant and lasting changes to the combined company's working practices, to our cost structures, and of course overall, to the portfolio.

Our underlying operational cost in 2016 are already at an annualized run rate of $40 billion, that's a quarter ahead of when we suggested we would achieve this, which is by the end of the year and that's $9 billion lower than Shell and BG costs were together in 2014, $9 billion. It should reduce even further on a like-for-like basis as the deal synergies and the ongoing other performance improvements continue to be delivered. We're delivering a lower and more predictable investment plans that be around $29 billion this year of which some $3 billion is non-cash. Next year, capital investment 2017 is expected to be around $25 billion, which is at the low-end of the $25 billion to $30 billion range we've previously communicated.

We are currently actively working 16 material asset sales, material meaning above $0.5 billion or more, and that's as part of the $30 billion overall divestment program 2016 through 2018 and simultaneously delivering profitable new projects. This is the biggest driver of the long-term performance. The start-ups this year 2016 alone expected to add more than 250,000 barrels of oil equivalent per day when we're fully ramped up.

Turning now to the financial results. Excluding the identified items, Shell's CCS earnings were $2.8 billion, that's an increase both year-on-year and quarter-on-quarter. On a Q3-to-Q3 basis, we saw higher earnings in upstream and in integrated gas and lower earnings in downstream. The return on the average capital employed was 2.8%. Cash flow in the quarter, $8.5 billion, that's cash generated before investment.

Dividends distributed in the third quarter were $3.8 billion, $0.47 per share, of which $1.1 billion were settled under the scrip program, so $2.7 billion in cash. Brent oil prices $46 were 10% lower than a year ago 2015. They're almost exactly the same as Q2 2016. Realized gas prices some 30% lower than we were in Q3 2015. So those lower oil and gas prices reduced the results year-on-year by around $1 billion and the refining and trading results were also significantly lower than the same quarter last year reflecting relatively weaker global refining conditions. Offsetting this of course, the uplift from the BG volumes, the lower costs despite the increase related to the consolidation of BG and lower well write-offs, they've all combined to deliver a profitable quarter despite those lower oil prices.

The usual waterfall charts by business are provided in the backup materials where you find details of the earnings for each business segment. As is normal for large transactions and it's worth reminding, BG was a $64 billion transaction. We have been reviewing the accounting treatment quarter-by-quarter and we intended in Q3 to put as much of this on a same basis to go forward as possible. That has resulted in an increase in the goodwill of around $1.5 billion, total goodwill $10.5 billion and some adjustments to the premium price allocation and the way that we then depreciate that. So that was in the third quarter a help to earnings of some $250 million in the Q3 earnings. This was as a result of the revision of that PPA. You see full details of this in the results announcement.

Moving on to production, the headline oil and gas production for the third quarter was 3.6 million barrels oil equivalent per day, that's 25% or [25%] higher than Q3 last year because the uplift from the BG acquisition accounts for most of this increase, but I think it's important to point out at the same time that our overall upstream operating performance continues to improve. There's a focus on margins, on reliability and available uptime for the facilities that really is delivering to the bottom line and doing all of that while we're seeing quite a substantive decline in the operating cost. The liquefied natural gas or LNG volumes also higher obviously also impacted and helped by the BG acquisition.

Turning now to the cash. Priorities for cash have not and I expect will not change. Debt reduction is top of the agenda followed by support for the dividend and then we think about capital investment and share buybacks. Cash generated from operations 12-month rolling basis was some $17 billion or excluding working capital, $21 billion and that $21 billion at an average Brent price of around $42 a barrel. The cash balances in the quarter on the balance sheet increased by $5 billion. We have $20 billion or so on the balance sheet. That was a result of the free cash flow performance and the increase in the gross debt.

Depreciation for the third quarter was $6.2 billion. On an underlying basis, this is around $5.5 billion. We are expecting an annual DD&A or depreciation charge of [around $22 billion on today's portfolio and downstream is just over $3 billion of that] and that's been a relatively constant figure, the remainder being upstream. That is [clearly $22 billion] is a substantially increased number with the new portfolio. 2015 the number was around $17 billion. That uptick reflects new projects on stream as well as the addition of BG.

So our gearing, net debt divided by total capital employed at the end of the quarter was 29%. Now, as we said before, we manage the Company through the down-cycle pulling on significant financial and operating levers. Now let me update you on that, all four of them. So firstly, asset sales. We are using divestments as an important element of the strategy to reshape the Company, not just the balance sheet but to focus our activities. So up to 10% of Shell's oil and gas production is earmarked for sale including several country positions or exits and a number of midstream assets to the master limited partnership or MLP in the US and also some downstream positions. As of today, we have 16 separate asset sales transactions above $500 million in progress. Only six of them is shown on this slide. This is the transactions that have been announced or completed and those that are known to be in progress.

This is consistent with all previous statements, increasing cash contribution towards the $30 billion divestment program and the $6 billion to $8 billion to be visible this year. So we have a value-driven and not a time-driven divestment program and clearly it's an integral part of the portfolio improvement plan. It is about high-grading the portfolio and focusing not just the balance sheet. We're not planning for asset sales at give-away prices and there's no reason today to think that we can't achieve the $30 billion figure with that proviso in mind. Year-to-date, there are $5 billion of divestments visibility on the slide. Getting this closer to the $6 billion to $8 billion guidance we gave you for 2016, we'd expect to be in that range and we have clearly further deals in the pipeline to deliver and to progress at least a similar amount in 2017.

I'll move on now to overall spending, the second and third lever is capital investment and operating cost. We continue to reduce capital spending and we continue to reduce costs across the board. Capital investment for 2016 is on track, $29 billion of which $3 billion is non-cash. Capital investment for next year, new statement, is expected to be around $25 billion, the low-end of the $25 billion to $30 billion range we previously advised and there's also likely be a couple of billion dollars there that is non-cash.

Our underlying operational cost in 2016 are already in Q3 at an annualized run rate of $40 billion, that's a quarter ahead of the plan and the intent that we previously highlighted. That $40 billion figure is $9 billion, almost 20% lower than the Shell plus BG costs in 2014, $9 billion and it should reduce further on a like-for-like basis. We haven't yet finished with all the deal synergies and some of the performance improvement programs that have delivered the $9 billion still have some way to go. In short and very simple terms, we just did a $64 billion acquisition, we've absorbed BG's entire cost base and spend into Shell this year, no increase. We're running the combined Company for the same cost and broadly speaking the same investment level. So no increase overall on a combined basis.

The fourth lever, of course, is delivering profitable new projects that turn investment or negative cash flows into very positive free cash flow. This is the largest single lever over the medium and long-term in terms of improving our financial framework. By 2018, the start-ups since 2014 [over a three-year period] in the two combine portfolios should be producing more than 1 million barrels oil equivalent per day. Almost all of it high margin, equivalent to around $10 billion of annual CFFO at average $60 oil prices. The cash operating costs on this set of projects around $15 per barrel and the statutory tax rate around 35%. So you can see, high margin both earnings and cash.

In the third quarter just closed, we saw the start-up of Stones in the Gulf of Mexico with 50,000 barrel a day, 100% Shell. The first cargo from Gorgon in Australia and the first export of crude oil was achieved at Kashagan in Kazakhstan.

I'll just turn now to the LNG supply and demand and the market dynamics that we're seeing this year to-date and maybe some questions arise for Maarten later. The LNG industry is clearly in the midst of a large series of supply capacity additions, no surprise as most of them take four years, five year to deliver. Over 100 million tons per annum of LNG capacity, these are under construction and has recently started operation. The majority of these capacity additions are in Australia and the United States of America.

As a result, in comparing the same period last year, so far, and this is the nine-month figures, so far during 2016, the market's grown by an additional 12 million tons of volume and most of that has been supplied from Australia, but obviously that gas has to go somewhere. So we're seeing a healthy growth on the demand side and that's more than compensating for the declines in the traditional North Asian markets and the Latin American market, which in itself is more a reflection of rain in Brazil and extra hydro power.

But this year, demand growth has been especially strong in the Middle East, particularly in Egypt and Jordan and Pakistan. Middle East LNG demand overall has gone up by around 8 million tons. The growing role of India and China are in the total global mix has been better than the (inaudible) LNG growth as well, each has increased by approximately 4 million tons so far. In the case of China, the increase is mostly the result of a ramp up of contractual volumes including from ourselves. And whereas in India, we are observing the effects of lower prices, changes in policies around power generation and fertilizer and lower domestic production.

As a result, the global LNG market is relying less on Europe, as the LNG balancing market with benefits of LNG finding its way to an increasingly larger and more diversified customer base. And Maarten, I'm sure, can go into more details on this in the Q&A because clearly as we go forward, a lot of value delivery from Shell and from the acquisition rests in how we are able to take advantage of that great LNG position on a global basis.

So to summarize, our investment plans and the portfolio actions that we're now taking to focus firmly on reshaping Shell into a world-class investment case. It will be thus at all points on the oil price cycle, because we aim for stronger returns and improved free cash flow per share. We are making good progress, you can see it in the results today towards the same in spite of the current challenging market conditions.

In parallel with the integration of BG, we have actually been managing the Company on an overall sense, through the down cycle, we are reducing cost just about everywhere. We are reducing investment levels and we are simultaneously executing the divestment and most of all, we are now seeing the startup and contribution from the profitable new projects.

So with that, I'd like to move on to the questions. As I noted, Maarten is here with me as well and please could we try and restrict ourselves one and two each, so that everyone has the opportunity to ask questions. Come back again a second time if you want to follow-up. So thank you for listening.

Operator, please could you poll for questions? Thanks.

(Operator Instructions) Oswald Clint, Bernstein.

And maybe one question each, please. Simon, just on the gearing number, the 29%, I think you've guided it pretty well the last six months or so saying it should trend up in the short term, which it has. But as you look at these numbers today and your CapEx guidance and your trajectory back towards to 20%, is that something you feel is certainly on the cards as we enter 2017, it's not a gearing number we should think about as maybe by the end of 2017, please. That'll be the first question.

And since Maarten's there, I'd like to ask about the Singapore LNG contract that you've just announced is, I'm curious is this more of your short-term gas in your portfolio or your short-term gas you're allocating to Singapore? And is that happening at certainly a better price in terms of our modeling? And then also I noticed that there's been a new 0.5% sulfur cap on maritime fuels last week announced by 2020, is that kind of feeding into your aspirations for LNG into transportation, is that something we should pay particular attention to Maarten, please? Thank you.

Thanks. I leave the second question to Maarten, it's a great story there particular on your second point on sulfur and marine. 29% gearing indeed, we guided low, if I just step back a year, we were talking about gearing in the mid-20s post BG. So what was changed since then, a couple of things, one is that the oil prices stayed level, that's probably cost us several percentage points, probably 3 percentage points plus, the divestments have been slightly slow, that's probably cost was another 1 percentage point. I think importantly, you will have picked up hopefully that the finance leases that we have recognized will have added to the gearing, these were operating leases in the BG books and we've actually added further finance leases both in Brazil and in the Gulf of Mexico since we completed the acquisition and the total effect of the leases has added 2 percentage points to the gearing.

On the flipside, our overall performance has been better and we've delivered much lower cost, so that helped the gearing. But overall, we're around 4 percentage points higher but 2 percentage points of those don't really count on the grounds that it's just an accounting change and slightly better off in that sense from one would hope for.

How do we feel for end 2017, well, certainly end 2016, it could go slightly up or slightly down in Q4 though it depended a little bit on divestments and oil price. But perhaps just to wind back to this, the FFO, the cash flow statement and tell you how these numbers fall through to us. The third quarter was good cash generation, but it's never really insightful to look at a single quarter for cash generation.

So if we look at the 12 months, just go back 12 months, 8 months of the BG included there, of course. We delivered $21 billion of cash flow, excluding working cap. If we -- now it's at $42 oil price. If we adjust that back to today's oil price, you can probably add $4 billion, maybe more. If you adjust for not only an extra four months of BG, that a clearly improved performance in terms of production and lower cost. There's another $3 billion there, and as we go forward into 2017, we will take more cost data and we will deliver more from the projects that are coming on-stream now because most of the large ones, Gorgon, Stones, Kashagan, haven't yet contributed to the bottom line. We've got two more FPSOs in Brazil to come in Q4. We have Clash, Galleon, Malakai, we are investing in the Permian. And there is quite significant cash flow growth to come. So you can easily see a logical path to low 30s cash generation, even at today's oil price.

We are then looking at next year's capital investment, maybe $23 billion or so of cash and a $10 billion cash dividend. Though absent divestments completely, it is not unreasonable to balance the books next year. Therefore, divestments could contribute directly to bringing the debt down. I would be a little disappointed if the oil price stayed where it is and the gearing was still 29% at the end of next year. If we deliver this plan, we should be in quite a bit better positioned than would be -- than we'll expect to end 2016. So hopefully that helps cover a few issues around gearing because it's not as simple as just another [outcome] number.

Maarten, can you enlighten us on Singapore LNG and some of the opportunities in LNG into transport?

Let me cover that question, then. Singapore. Simon?

Yes, Maarten, go ahead, please.

So yes, we're very pleased to get the Singapore license awarded, we inherited from BG of course a 3 million ton exclusive license that was almost full in the sense that they have contracted 2.7 million tons. And these are rights to contract to long-term volumes. So we've now been able to add to that another 1 million ton long-term tranche into Singapore. So in total, we'll be selling 4 million tons of LNG long-term into Singapore and so this will grow, this will come from our portfolio, but it will reduce our near-term and long-term length another 1 million ton of premium market excess. So we're very pleased with it, but it's not necessarily the only focus at short-term volume. The volumes will (inaudible) into the 20s and early 30s. And interesting in this case, we are able to share of our own demand, we have 0.7 million tons of LNG demand with Bukom refinery and Moerdijk Chemicals complex that we are now able, as of 2018 to serve through the Shell network, and integrate the whole value chain.

On the transport, indeed we have been focused on energy to transport is a very important new sector for LNG to serve going forward because the heavy transport can't electrify, so gas would -- is quite likely the kind of destination energy source for heavy transport. And if you convert the current shipping markets to LNG in its totality, you would find about 250 million tons of extra LNG demand and on the onshore heavy trucking and long distance market, it will be about 500 million tons. So that put together be three times at current gold global energy supply. So very, very important in material sector for us to slowly unlock. Also the sectors have good affordability, they don't have coal as an alternative of other sources, essentially the alternative as oil and that's a price link that we like competing with in the gas side.

So the IMO decision to cap sulfur emissions down from 3% to 0.5% is a very big step change in the shipping business. And what it will require ship-owners to do is to either install scrubbers to try and bring their ship emissions back to within this limit or to shift to LNG. And what we see now at quite a rapid rate is that new builds in shipping are shifting to adopting LNG and that some of the older ships are actually being considered for putting gas turbines into the ships.

So very positive development for the LNG business, we are well placed, we've been investing ahead of the curve in this business, we have supply points in Europe, we have won the supply point rights in Singapore, we are setting up supply points in the Gibraltar, in the Middle East and in the Americas. And recently celebrated a somewhat iconic contract with Carnival Cruisers who ordered a total of potentially up to 13 big cruise ships that run on LNG and we got the exclusive rights to supply them as they come on stream.

So I think this is big news for the industry, it will still be a ramp up of volume over time as shipping industry and trucking industry converts. But it is a major new sector with good affordability and a sector that given our downstream industry -- our downstream footprint, we are very well placed to serve.

Many thanks. It's a great story. We're taking the next question.

Thomas Adolff, Credit Suisse.

Two questions from me as well. One for Simon and one for Maarten. Let me begin with Simon, maybe if we talk about -- if you look at your priorities for cash, you've mentioned that debt reduction is a top priority, but perhaps if I put it differently, is maintaining the A credit rating state is more important than preserving the dividend? That's my question for Simon.

And for Maarten, I think we talked about where you've given some unrisked figures in terms of upside from LNG to transport, et cetera, but if you had to give a risked figure for the IMO related demand growth to say 2025, in addition to a risked figure for FSRU related demand growth to 2025 what would that be for the LNG market? Thank you very much.

Thanks, Thomas. Again I'll obviously leave the LNG for Maarten. Priority number one is debt reduction. We need to bring the debt down. The question between credit rating and dividend as well and I hope not to have to face and practice at the moment as I hopefully just indicated its tight and is close and it does require oil price to stay roughly around $50 that we should be able to manage reasonably well through the next 12 months.

It is clearly important. The debt reduction is a proxy for maintaining the credit rating. The credit rating is very important. I think we could effectively survive one notch further. We're AA with one rate agency and A with the other, so three notches different. So we could survive some level of danger as long as it was clear how we're going to get those ratings back. And the best way to getting the ratings back is fundamentally to work on the numerator early the ratio, take cost out, keep it out and deliver those new projects.

So each quarter we see a little bit more of that, but clearly as the divestments reduce the denominator, the debt in the short term. I think we are out to do both to ensure that we keep the debt markets and the equity markets happy and comfortable. And we're quietly confident that the underlying performance of the portfolio is moving into a position where we can achieve that. Maarten?

Yes. Thanks, Simon. If I start with LNG to transport and that's the one with the biggest range of uncertainty, but that range probably caught up this week with the IMO announcement. And the range -- I would use for the 2025 volumes something in the range of 35 million to 60 million tons of LNG to go into transport. That does include road which isn't affected by IMO. The IMO is only for ships, but roads -- LNG for road transport is also ramping up over the period. And it would then into the 2030 could well potentially break 100 million tons and before the end of the decade if growth indeed continues and this partly depends on infrastructure being built of course.

And if you then look at the rest of the LNG market, we see it grow between 150 million and 170 million tons between now and 2025. And your question was about FSRUs and there is of course also market growth into onshore terminals that are not floating regas units, but basically a country like China and India, but also Europe where not FSRU is used, but the larger tanks -- tanks in ports. The shift -- there is probably about a third FSRUs, two-thirds bigger onshore import facilities, if I got your question correct. The FSRUs are predominantly Africa, Latin America, Middle East and Southeast Asia on land infrastructure very much built into China, into Europe and to some extent in India as a bit of a mix. So that's what the import picture looks like. So you've been looking at a range of about 420 million tons and the high-end of 440 million tons, 450 million tons depending on exactly how fast a transport business indeed grows.

All by 2025.

[Dipan Dovelingin], Exane BNP Paribas.

Three questions please. Firstly, Simon, could you just talk about the scenario then beyond paying down debt, how we should think about the Group turning off the scrip? So what type of debt metrics should the market look for or is there a signal on the oil price, a particular level where you think the scrip can be removed, because it is arguably dilatable increasing that dividend burden in the long term? Second question is relatively Vanilla could you give us an update on Prelude startup and what remains to be done in terms of commissioning? Thank you.

Many thanks, Dipan. And we are having Maarten available. I will pass Prelude to you because it is your project Maarten, but not too many details please. Scenario beyond debt reduction, a key trigger you will feel and we will feel comfortable that the financial framework is rebalancing in our favor, will be to turn off the scrip dividend. Fully agree with you that the dilution and the additional dividend are not something we want to live with forever and would like to address as soon as possible. This combination of two factors is likely, Dipan, first we actually have to get the metrics moving in the right direction. The debt must be coming down, but then must be doing it in a sustainable way so that we don't take the scrip off and six months later find ourselves having to put it back on again. We're on a feeling that was the prudent thing to do. So I've said before, we need to have line of sight to gearing of 20%. That to be honest is just a good proxy for the overall rating metrics and indeed where the oil price settles out will be important. For the next 12 months we see the oil market by and large in balance in terms of supply and demand. Thereafter it's likely that the demand to continue as various demand strips supply and where the oil price settles out in that period will be a factor, no question.

But before then I think we need not only to deliver, if you like, the organic cash balance that I talked about, getting the cash generation up into the low 30%s, but we need to do this in divestments and that will start to turn the metrics. But really you need the net debt heading down more towards [50] than running in the [70s] before we would look at the scrip. But it's really about being confident in the sustainability and not just to go and offset the numbers. And Maarten Prelude.

Yes, thanks Simon. I was -- and Dipan of course, I was a recently on Prelude to review progress. We've been busy steam blowing in the third quarter. That's getting close to being finalized. So we're really into a period now where the major construction work is over and we're into starting commissioning handing over to operations and working things up. So this progress is solid. It is as per our plan, which means that the message about getting substantial cash flow from prelude in 2018 is still very much on and increasingly looking derisked as we progress this project. So going well and looking forward to cash in 2018.

Great, thanks Maarten. Operator, next question please.

Jon Rigby, UBS.

Two questions. First is the quarter -- this quarter looks -- resembles much more like a quarter at the current macro that expects Shell to deliver. 2Q didn't and I know 2Q it was a little bit of backwards and forwards about why it was such an odd quarter. And I just wondered whether with a bit of time after the second quarter and also reviewing the third-quarter results whether there's any more insight into that delta 1Q to 2Q, 2Q now to 3Q that you can share with us and maybe sort of confirm the third quarter as you would say it is much more resembling the financial and operating performance of your underlying business if that were possible?

The second question is just on the downstream. The marketing result looks very, very strong results. If I look back against history, when you have disclosed those numbers, it looks right at the top end and yet if I look at the macro, it's not obvious that it was a quarter where marketing should do fantastically well, it wasn't -- we didn't see a huge drop in oil prices. It wasn't obvious that demand was going very strongly. So I just wondered are you able to sort of share something about why marketing was such a standout result in the quarter? Thanks.

Thanks, Jon. An important question in the first one. Certainly it was not easy to explain Q2 because there were quite a lot of small factors that in and of themselves were a bit one-off and some of them have reversed in the first quarter as well. So I said about 400 million has come back into the third quarter, most of which, in fact all of which, shows in the upstream results. Maarten has got 100 million negative upstream, probably got close to 500 million positive.

I talked about the adjustment to the PPA, or the purchase price allocation, premium allocation from the BG acquisition. So there's been a true-up of depreciation and actually in practice, a reduction of that step-up on the PPA, while we previously talked about $300 million a quarter. I think going forward, that step-up will be more like $200 million a quarter, although it will grow over time as the production continues to increase.

And then there's a couple of tax items which also either reversed or were one-off in the third quarter. So Q2 underlying understated to an extent, Q3 slightly overstated. Q3 is more representative, although I would note that refining margins in downstream were particularly weak and the chemical still has more earnings and cash generation power when all the crackers are running. So clearly, in the fourth quarter, what we will be watching is, one, the oil price; two, whether the cost come out and stay sustainably; and three, the new projects, all the ones I sort of talked about, Gorgon, Stones, Kashagan, two FPSOs in Brazil, they didn't actually contribute a lot to the third quarter financials. They should all contribute more to the fourth quarter financials. An uptick of revenue generation, continuing lower cost, and the oil price staying $50 for at least a month should help the fourth quarter and both should be more representative than the second quarter was.

I did also say that we expected -- 2016 is a transition year. We're just buying together two enormous companies. There will be a little bit of noise in the results. We tried to take as much as possible in Q3 so that we are cleaner going forward into the new year and the 2017 would be an easier year, not just for you, but for us.

Downstream marketing, indeed, it's strong but fundamentally, we are seeing premium marketing. It's working for us. In retail, we are getting a stronger unit margin from penetration of V-Power and management of the price-demand elasticity.

Lubricants, we are very well placed in some very important markets, particularly in China where it continues to grow successfully. And again, premium product penetration, stronger unit margins is making a difference. We're about 30% up year-on-year in terms of contribution from marketing and that's good, but it is sustainable. It is a result of a significant number of genuine marketing problems. We're not just wholesaling and moving the molecules. We're marketing.

Finally, we did actually, although [with gas], the LPG, we've seen aviation pick up on the fuels business. So our actual aviation margins were better as well. So strong performance across the board but sustainable. It's not just a one-off.

Rob West, Redburn.

I'd like to ask my first one on the [Gum]. I think there's a couple of wells in the southwest part of your Norfolk acreage leased by Castle Valley, one of that I think was Dover. Is there any update on that this quarter? And just looking back at the well you announced last quarter, is that something that could become a hub around the southwest of that position, or is this stuff all just tie back to (inaudible)? That's the first question.

The second one is, maybe for Maarten, maybe for whoever who prefers it, just interested if you can tell me about the onerous contract provisions you took in LNG and a bit of what is behind that?

Many thanks, Rob. I will handle the gum. I think the onerous contract there is gas tolling into Spain. So, Maarten, can you cover that?

Yes.

On the gum, you're right, the Norfolk plays and the Eastern Gulf of Mexico and we were the first in there and we're effectively partnered with NEXON, but there aren't many other people in the region. The Appo discovery keeps growing, both from nearby discoveries and itself. We took the FID on Appomattox last year. We are seeing the original breakeven price range [55]. We've continued to take costs out, so that breakeven prices now start with a [4] and we're continuing to look for further opportunity. And one of the things that's helping is greater volumes.

You are right that Rydberg last quarter was a success that we are now drilling in Castle Valley and I'm not sure about Rydberg at the moment but we are effectively not announcing anything there at the moment. We have used the early-mover advantage to take further acreage in the region. And is this a hub region, well, absolutely once Appo is up and running, we're talking of 220,000, 230,000 barrels a day. But we are already looking at whether and how we could debottleneck, because it is quite clear that the discoveries we already have we'll keep that full for quite a lot of years and there is still further potential. So it will be at least one hub, one pipeline back into the Gulf Coast. So it's looking like a great opportunity and on average where something close to 80% of the holding in the acreage with most of the rest being, I thought the nearly all the rest being held by NEXON. So it's a good partnership, great prospects, the hub development already in play to two to three years before it produces, but it will be one of the major cash generators for Shell into the 2020s.

Maarten, onerous contracts.

Yes, I think that's a contract that was from the middle of the last decade, 2005 a tolling deal in Spain, the type of which we haven't really done since then. We had a few turning deals in the states as well in the period. None of them worked out very well. And this deal particularly has been under water for most of its duration. We only now had four years to go and there were no plausible price scenarios anymore where this contact would ever get back into the money and therefore we wrote it off as a -- the last four years it offered an onerous contract. You can't do that too early in the life of a contract. Although, even four years ago, we didn't have much hope with our rules around how far in advance you can recognize this given the markets are volatile. But this what we send out so far the money that we were able to take out of the books and forget about it.

Thank you, Maarten. Move to the next question please.

Irene Himona, Societe Generale.

Good afternoon Simon. Two questions, first on the cash flow. So capital expenditure in the nine months is shown around $16.4 billion. You are guiding today to effectively $26 billion cash CapEx for 2016. Are we looking at $9 billion to $10 billion for the fourth quarter CapEx and related to that your DD&A guidance for this year $22 billion. Could you kindly give us some guidance, some sense of what happens to DD&A next year please?

And my second question just on Brazil where obviously they've changed the legislation recently to relax the requirement for Petrobras to operate everything in the pre-sold. How is Shell strategically thinking about this opportunity, please? Thank you.

Irene, thank you. On the capital investment, I have to say we focus more on 2017, 2018 and 2019 than we have been doing on the next three months, because that tends to be locked in. And maybe at $29 billion , it's a little bit rich, but that's not going to drive the metrics too much one way or the other. We do have a couple of one-off items in the fourth quarter including the payment to enter the chemicals developments in Guangdong Province to CNOOC in China. And we have additional FPSO coming on in Brazil. So well let's see how it turns out. I would regard $29 billion as the maximum. The DD&A is $22 billion for this year that will be how it starts next year, but I think over the year as we see the following come on stream and ramp up, it will increase. We will see Kashagan kick in for full year. We will see Gorgon Train 2, Train 3 hopefully come on stream. We will see Schiehallion and we will likely see some of the tiebacks in the Gulf and a ramp-up in activity in the Permian. So I'd expect all of those to drive depreciation up but it will then be driven down by proved reserves bookings at the end of 2016.

I don't yet have a fix on that simply because we don't do the work in detail until basically November-December. So over the next quarter, we will get a fix on the DD&A. But the figures I gave earlier on the cash flow that are not impacted by DD&A and obviously the earnings that go with them would be. Hopefully that helps.

In Brazil, it's early days really. Indeed there have been statements about changes in requirement on operatorship, level of ownership, how local content plays in and in principal very interesting. Brazil is going to be one of the top four countries in Shell along with Qatar, Australia, in the US, probably already is in terms of current value generation today. And we're investing up to $3 billion a year there for the foreseeable future as we continue to build out the FPSOs.

So clearly we're interested in consolidating on the good assets in the country and looking at further opportunities to create values on the assets we're already involved in. But it's still a little early. I think Petrobras is an excellent operator, while we worked together with them in the sub-shell. BG had good relationships, Shell had the relationship in Libra and on the back of both BG and Shell have been able to bring, I would like to think that we would have further opportunity in the future, either on assets or in the way that we govern and operate, that's for the future.

Right now, we are focused very much on two FPSOs this year and another two next year. That will take us to 11. There are another 4 on order, under construction, 15 FPSOs on BMS-9 and 11 and getting those up and running while we also start the first one or two on Libra that's quite a challenge and a fantastic business.

Okay, hopefully that was of interest to everybody, important areas of performance. We can take the next question please.

Guy Baber, Simmons.

You're giving clarity on 2017 CapEx a little bit earlier than normal which we very much appreciate. But relative to that prior range of $25 billion to $30 billion, can you just discuss the rationale behind the decision to guide to $25 billion at this point? Is that reflective of efficiency capture, meaning the low end accomplishes pretty much everything that you wanted to accomplish before. And I'm just curious how fluid that guidance is at this point in time to better understand the commodity price assumptions and under what pricing scenarios you might flex that higher or lower. And then I had a follow-up.

Thanks, Guy. Good spot, this is at least three months earlier than we would normally communicate next year's capital investment. And to an extent, it's slightly easier than it normally is because the reason it's going down from this year is we actually finished projects. I won't repeat the list of projects that I've just stated but we stop spending on those projects. And we're not taking significant new investment decisions. I mentioned Appomattox earlier. We're investing in chemicals both in Pennsylvania and China. We continue to finish off, obviously Prelude and we're investing in subsea activities whether it's Nigeria, Gulf of Mexico or the North Sea.

So there is still quite a lot going on and we gave a range of $25 billion to $30 billion as being book-ends that were not necessarily associated with the top and bottom of the price cycle. But in terms of affordability, obviously they are. $25 billion would seem to be a soft floor. So if we have to we can drop below and $30 billion is a hard ceiling. We will not go above $30 billion even if we have the cash until we have embarked on the buyback program which is post scrip and certainly when we're in a better financial framework overall.

So, as we said we are years away from that. So that's why we stated on the range. Why $25 billion now, we are coming off a very significant investment and our priorities are to reduce the debt and therefore it's appropriate, but we don't have to jump into new investments that we focus on maximizing the value from the investment we've just been making.

Can we go lower, is it flexible, to an extent, yes. The lower prices would drive that. So we will be driven by affordability in the short term, not necessarily in the medium term, but very much so in the short term.

Water else has driven that down, well the supply chain costs have helped but to be honest, it's a lot more than that. The whole industry, but particularly Shell, we've taken a pretty close look at why did costs go up so much in the first place with some of it. It's just the ways of working, the methodology, rather simple things like how you manage the logistics, the boats sent to offshore platforms or design standard valves, et cetera. And there's has been a huge momentum working in many cases positively with the supply chain just to take us cost out.

Now we're not doing a lot less, we're doing a bit less, so a lot less cash, it's a bit less activity for a lot of cash. That will continue and gives us some hope we can keep it $25 billion if we need to or go lower without compromising medium and longer-term growth prospects. So $25 billion was actually stated as being a level we believe gave us some moderate growth, not significant growth on the portfolio remembering the balance sheet is, currently, take the cash out, is $245 billion of assets employed in the business. So $25 billion is only 10% and is only slightly higher than the ongoing depreciation. So to go much further down is possible. I wouldn't say it was likely in 2017 simply because it's already in place. But if as we go forward, the price is further pressured downwards we will continue to take cost out or activities out.

You said you had a second question, Guy. Go ahead.

Lydia Rainforth, Barclays.

And I just had one question as it is, coming back to the OpEx numbers and the underlying costs already being at the $40 billion run rate that you talked about back in June, what has actually driven that? Can you give us some examples of where the costs have come down and just any indication in terms of how much further they could go also when we might see that coming through? Thanks, Simon.

Lydia, thanks. Interesting tables at the backend there of our results announcement on pages 21, 22 and 23 give bit more detail about things like returns, divestments, CapEx, clearing and operating expenses. What we have done is actually split out of the face of the P&L statement, the total operating expense, which this quarter is almost $10 billion exactly, and therefore $40 billion run rate, but also adjusted for the one-off items that we effectively include in identified items in the earnings statement so that you can actually see underlying operating expense $9.2 billion in Q3 and is $28.5 billion for the year to date. And that includes eight months of BG, and that compares with nine months last year, $29 billion not including BG. Hence the comments I made earlier.

Where does it come from? Well, pretty much everywhere I have to say. If we look at our costs above the assets, so finance, IT, HR, legal, we've taken out if we look 2015 through to 2017, somewhere like 25%. That's been done partly by delivering the synergies from the deal. We don't need to do certain things twice, but has been done through doing things differently, fundamentally, simplification offshoring of work to centers in Chennai, Bangalore, Manila, Krakow, and simply by doing things simply. On the asset, we have had quite significant programs in the upstream around operational excellence that have focused on better availability effectively managing the wells, the facilities and the reservoir in a more far sighted manner and one that sort of builds in the cost over a period of time and is actually driving unit cost down in particular and I think there is -- it's a bit of an intangible but bringing the BG guys into Shell is obviously a bit of internal competition as to how far we can we go. So good ideas and almost everywhere we look, the cost is improving. Now the total figures have benefited from foreign exchange movements to an extent. So some of that reduction and depends how you measure it, maybe up to a third is FX driven, but again while the dollar remains strong, that remains the situation. If the dollar gets weaker, typically the oil price goes up. So, there's a bit of a hedge in there as well and what we are still saying is we've got quite a long way to go on those performance improvement programs that I referred to in the functional cost tariff.

For example, I just gave you the 2017 target, which is quite or [in 2010 versus 2015]. So it's quite a lot better than 2016 in and of itself. Don't know how far it will go. Reluctant to give a headline target because in the downstream for example, we are allowing them to spend more in certain areas such as trading and supply where they are taking margins from new short positions and then they are marketing back to the earlier question which I think was from Jon, you can't get premium marketing margins without spending a bit of marketing money, but if you get $2 back for every dollar you spend, it's the right thing to do.

Therefore, we don't set headline OpEx targets, but we do look very carefully through what were now quite well defined cost management frameworks. Each dollar, where its being spent? Is it benchmarked? Is it competitive? Can we afford the ultimate impact on the performance unit that's actually delivering? And it's quite a well-established rhythm now of performance appraisal on that basis and it is just working. I probably shouldn't say it, but its actually positively surprised us internally as to how quickly the momentum has been achieved. Let me thank Lydia and go to the next question please.

Lucas Herrmann, Deutsche Bank.

Simon and Maarten, good afternoon, a couple if I might. Simon you've mentioned the Permian two or three times on this call. I think Ben described them as sleeping beauties but it sounds as though they're starting to wake up. Can you talk a little bit more around the way you may be thinking about that acreage plans, rigs activity et cetera at this moment in time. Secondly, I wondered if you could give us a little more flavor on the [2016] $500 million plus divestments that are ongoing, just flavor in terms of to what extent or how near or far some of those may, may not be to actually hitting the headlines for want of a better phrase and finally I've got to ask this, South America, Brazil, if I look at the regional profit performance, we've seen a [$700 million] net income turnaround in that business. I wonder if you could provide some explanation. I know barrels are up, but the profit improvement is dramatic.

Sure, the simplest answer on the last question I think Lucas is some of those one-off reversals that I mentioned earlier relate to depreciation in Brazil. So something around [$200 million to $250 million] positive in Q3 that was negative in Q1, Q2 and there's a bit of tax assistance as well, plus more barrels, lower cost probably is the big driver. At Permian, what will we do? We have 300,000 odd acres. We bought most from Chesapeake some time ago. It's great acreage. We're in some of the sweet spots and to date, we've been investing somewhere between $500 million and $1 billion a year, but it's been on appraising rather than producing. I think it's fair to say a lot of that acreage is in joint venture with Anadarko.

We are operating four rigs at the moment, likely to go up to five. Anadarko's operating similar that we are certainly from a Shell perspective in our operating acreage, we're now looking at moving to what we call the harvest phase. We know what we have, now we start to harvest some value. About -- well just over half of our Permian acreage we believe is breakeven price below $40. We have 2,500 locations that we've already identified that should work below $50 and there are three particular what we call common value areas that we are now looking to develop and we will start developing those and this is real genuine pad drilling, moving to the manufacturing approach as opposed to drilling one or two wells in a section and moving on once you know what you have. So you move onto 10, 15 maybe more wells per pad multiple horizons et cetera.

So it's actually quite exciting as we look forward. It's good acreage and we want to be part of developing that. We've also recently re-contracted some of our evacuation infrastructure and halved the pipeline costs going out for us, which is one of the reasons we've not developed previously as well. So we're in a pretty good place in the Permian. Sometimes you [lag] a bit more sometimes you might want to sell at the margin, but the core of the activity is a great quarter overall shales business.

2016 divestment, well, there are six on the slide, two of which we just announced in Canada Shales and in the Gulf of Mexico Brutus. The other four of the six were at the bottom of the slide that I showed, so Thailand, New Zealand, UK, and I think, Gabon. So there are a series of transactions currently close to a milestone. When I say a milestone, its either we agree or we don't. So a price and a deal. So when we have [$5 billion] announced or on the slide, we've talked [about $6 billion to $8 billion] clearly in progress during 2016. I would expect a small number, but certainly not a zero number of announcements between now and the year-end that will take us into the [$6 billion to $8 billion range, hopefully closer to $8 billion than $6 billion].

Behind that, there are other transactions and of the total, a further -- well six are downstream -- sorry, five are downstream, 11 are upstream. So it's basically, its [two-thirds] and they are not the only things we're working on either. They are more either smaller or slightly further down the cue, but the 2016 are the ones that I see on virtually a weekly basis at the moment. The progress that we are moving through on that will deliver the next $6 billion to $8 billion next year.

We fully understand and appreciate the importance to get some momentum in this program to see some significant runs on the board and cash in the bank in the first half of next year while the uncertainty around the oil price is greatest. Let's see where the oil price goes beyond that. That's not to say we stop the divestment program, but there's a question of balance in terms of the priorities. So hopefully that gives some flavor. I don't want to go into naming names of the ones that are not on the list already, but none of them is $5 billion or above but they are all above $0.5 billion. That's all I can say really. We're not going to do three $10 billion deals. We may end up doing 15 to 20 solid significant deals and we do have the resource and the asset base on which to do that.

Iain Reid, Macquarie Securities.

First question for you Simon. You probably saw what Exxon said on Friday about looking at their reserves. They did kind of pre-release of this, I know you said you're going to be doing it at the end the year but appreciate your comments, if you could. They basically said they were going [de-book] Oil Sands due to the current environment. Now you got a pretty similar asset there. So I'd be interested to get your view on that. And question on Maarten, US LNG, they seem to be saying that it's not going to Europe at the moment, but you got other areas where it's more profitable to take it. I presume when we get the big volumes coming, it's going to have to go to Europe and I'm just wondering what your outlook is for European gas prices when that starts to happen?

Iain, thanks. Obviously, I'll leave the second question on Maarten. On reserves, indeed, we look at these in November/December and I won't comment on competitors directly but Oil Sands mining we have, obviously the Athabasca Oil Sands Project is two mines. There's 1.94 billion barrels of oil in proved reserves today and $100 million or so are positive earnings and roughly that amount slightly less in positive free cash flow in the third quarter earnings. So at $46, Oil Sands is both earnings positive and importantly, free cash flow positive. I say importantly because the challenge with reserves in a low price environment is the need to pass the economic limit test. You need enough reserves to be able to share a positive forward cash flow and that's probably all I can say is if we're positive at $46, we should just about be okay I would have thought at whatever the average price for the year turns out to be.

Elsewhere in the portfolio, low prices could possibly have an impact, but of course, it would not necessarily make much difference to the operation or the value embedded because it merely is a mechanical spreadsheet extrapolation of the price, the historic price based on approved volume number only which may not be anything like the total resource associated with an asset and the current balance sheet. So it's basically into a sausage machine. I can't comment either way until we've done the work, but Oil Sands interestingly looks reasonably positive. Maarten, on US LNG?

Yes, thanks Simon and thanks Iain for that question. Indeed in the early days of US LNG, the best way to deal with [escargo] has been to keep them in the Americas and send them to Chile or Brazil and that's where they've sort of the our allotments have been ending up, but you're right to say as that production volume ramps up, there won't be enough demand in Latin America necessarily to absorb it all. And it is going to have to go somewhere. There is just a long-term comment and then a short-term comment. The long-term, the way I see prices move in the kind of medium-term is that the recovery in oil price is going to drive initially mostly Asian prices up simply because a lot of the Asian business is oil linked and that will drag prices in the Asian-Pacific basin up, also that's where [most demand growers will sit]. And then Europe will kind of sit in between depending a little bit on whether on the balance in the market on that moment in time where it will more follow Asia or whether it will sit at the kind of US plus rate differential.

In the near-term, what we've been seeing is two things. It's actually price, price spreads widening. So at the moment, we see Henry Hub [south of three European gas prices back to about six and we're selling LNG spot in Asia-Pacific at seven again]. So these are prices were certainly the way our (inaudible) contractors is established -- we would be able to send the volumes either into Asia or into Europe and make a margin. The demand trends that Simon highlighted on the slide he showed on the LNG market are quite profound. You saw the Middle East grow by 8 million tonnes that is from a total of 8 million tonnes last year and first nine of the months. So that's a doubling of the market and we've just had Egypt announce a tender for 96 cargoes for 2017/2018, 96 cargoes, that's [about 36 million tonnes] of LNG.

We see similar numbers or similarly large tenders coming out of India and other places by new customers. So I think in the near-term, there is more opportunistic demand partly driven by lower prices that I think will attract LNG from the US, but clearly the lower priced contracts and we have the best one in the business through Sabine Pass ex-BG will be the ones to benefit first. In a very negative outcome, you could see the higher-priced contracts, running into a place where they don't actually operate at all, but I'd say, I rate it as a lower probability and certainly we are not in those contracts.

Thank you. Maarten. Operator, next question please.

Christopher Kuplent, Bank of America.

Hello, thanks. I'm going to keep it very short. Simon, I know this sounds like Groundhog Day me asking the same question on every call, but given that we've seen Total again in the market issuing hybrid bonds with coupons near 3%, wanted to test yet again your appetite for doing the same. We've talked about protecting your single A credit rating et cetera, how attractive do you think is that route relative to asset disposals or indeed exacting another notch downgrade to A minus? Thank you.

My memory isn't good enough to remember it's always you, so you're off the hook. Hybrid bonds, we go to market and we get very tight pricing even with the lower credit rating that we've been achieving with S&P. Hybrid bonds are not cheap financing, they might contribute to the rating but they are expensive and the carrying costs, it is expensive as is discounting your dividend, we do not need to do that. If I needed to do that, then maybe we think about it, but we don't need to do that. I will continue to stay plain vanilla in the capital markets, with debt capital market and for long as that is by far the cheapest and easiest available source of debt to me. And it's really, probably the same answer I gave last time, Chris. It's relatively low quality source of finance, and not cheap. And just for avoidance of debt with everybody, I do understand that nor is equity issued through Scrip, hence the earlier comment about high priority, reduce the debt, so that we can take the Scrip off. Thanks, Chris. I'll move to the next question.

Jason Gammel, Jefferies.

Thanks very much. I had two questions, please. First, Simon I wanted to come back to some of the comments you made around both the divestiture process and the Permian. The Permian does seem to be one of the few places globally where upstream assets are attracting some pretty solid valuations and you've referenced obviously being in a very good neighborhood there. So what do you think about the idea of monetizing some of the acreage position while maintaining your core and putting a pretty solid set of runs on the board from a transaction there?

Second question is on the LNG business. The sales volumes are now up about 50% from prior to the BG merger, I was just wondering, Maarten, if you could talk about how the scale and flexibility have changed and how that affects -- how you run that business, thinking in particular in terms of accessing new customers and have even potentially terming out some of your hub linked and spot contracts into longer-term?

Jason, thanks. Obviously, I'll leave the second one for Maarten. You're absolutely right, Jason, the hottest properties on earth at the moment seem to be in the Permian, we have 50,000 acre (inaudible) going rate. We actually have two smaller packages on the market at the moment at a good acreage, they're not that contiguous or close to our likely development activities. So let's see how that process unfolds.

More generally, in terms of the Shales business as well as thinking why do we want a Shale, well, probably because we can, we have great acreage, 12 billion barrels of total resource we've talked about previously, five basins, Argentina, two in Canada and two in the US. And as a strategic element of the portfolio, it offers an optionality and a flexibility that we don't get in the rest of the portfolio, i.e., we can ramp investments and developments up and down according to price and opportunity. If we don't have that in the portfolio, then we don't have that optionality and we have less resource with as well. So that's the reason we want the Shale business, the Permian is to an extent, currently and possibly for quite some time. It is the crown jewel, not just in terms of the value and quality of the asset, but also the capability that is being developed there. We and the industry learn more when there is more activity ongoing about how to maximize the value.

So it is important for us to be in the Permian, but that doesn't mean we need every acre that we currently hold, no, but we're not interested in adding acreage and the "patchwork nature" of the acreage across the basins in which we're interested may offer opportunities over time there as well. But the aim is focus so that we end up with a more efficient development program and the areas or acreage that we not likely to invest in the near-term, but we sell them rather than leave them sleeping. So that is the aim. So we're actually, at the moment, following your advice. There was small enough packages not to be on the list of 2016 because there was a materiality criteria. It'd be interesting to see if by the time they get priced, they creep onto the list of 2016.

And Maarten, sales volumes and LNG in general, what the thinking is?

Yes, thanks for the question. We could spend a bit of time on this if we wanted to, but I'll try to keep it short. Indeed, our LNG volumes are -- our sales are now about 15 million tons a quarter. So that brings us up to well over 50 million tons and actually close to 60 million tons a year, which is almost 25% of the current LNG market. So that clearly gives us enormous footprint in terms of supply options.

And there's a few things for us. One is, in the LNG market, the business model of finding a big Asian utility to take 4 million tons at a high oil-linked price off your [hands at high seas] is still going to be relevant going forward, but it's not where the growth is. The growth is in smaller customers that look for smaller volumes, often of worst credit and also often only have one or two contracts in their portfolio, and they need security of supply, they need certainty of delivery. And in many cases, what we're actually finding is, it is easier for us to win the business with those customers because we have so many supply options to give them security, but also because we are one of the very, very few suppliers and the State of Qatar would probably be the other one, that doesn't need a condition precedent on a future FID when we make supply promise because we have enough size and flexibility in the portfolio to promise someone 1 million tons or 2 million tons without having to take an FID to back that up.

And that isn't only the case with customers, that is also very much to the case with countries who are starting to import LNG for the first time. Jordan is a case in point. We didn't get the business in Pakistan, so it doesn't always work, that went to Qatar. But in many cases, these countries are looking for certainty of supply because they're betting a part of their energy system on gas and they don't want to be beholden to an uncertain FID.

There are also other ways in which this footprint helps us, and it's not only about size, but it's also about the ability to absorb and manage risks into our portfolio where customers -- risks these customers can't take by themselves, we find people that in the rush to commit to US-based energy supply, signed up for supply from the US to Asia and now regret having the contract in their portfolio and really can't manage it. We have a number of instances where we actually take over those regret contracts, we absorb them, and we do much more plain vanilla often longer-term, higher volume deals with them in return. We can absorb the risks that they don't want anymore, much easier than them.

So it's risk management, it's volume and it's basically the ability to make offers that are -- that have no CPs to them that I think differentiated in the market and make sure that we are at every -- we are aware of every piece of demand and every piece of open supply in the market. And quite often, we're able to connect the two much easier than individual parties who just basically are not in all these conversations at the same time. So the network of people and contacts we've built up is unique and gives us trading opportunities every day.

Biraj Borkhataria, Royal Bank of Canada.

Thanks for taking my question. And one final one for Maarten. For Simon, just following up on your comments on gearing, you're currently at 29%, but you did say that 2% of that doesn't really count. So I was wondering if I should think of your -- should I think of your gearing ceiling as 32% rather than the 30% you previously talked about? I don't know that's a fairly small margin, but given you're quite close to that, I though it's worth asking.

And then for Maarten, just an easy question, could you provide any kind of update on Lake Charles and how that's progressing? Thank you.

Thanks, Biraj. I mean, you're absolutely right, the like-for-like, when we started talking about 30% that the 2% is different because it's on balance sheet, finance leases. The rating agencies look through that anyway, that figure is considerably higher than the 77% that you see on the balance sheet today. So 30% is just a proxy for their overall metrics, it's not an immediate trigger, either to them or us if we go through 30%, it's just a signal that we need to be giving extreme priority to bringing it then again because if we stay above 30%, whether it's 30% or 32%, that becomes a less sustainable financial framework over time. So stick with 30% as the proxy, that's what we'd like to manage to, [if you just remember], but like-for-like indeed, really it's 2% higher in terms of the economic substance.

And Maarten, Lake Charles.

Yes, thanks Simon and Biraj. Lake Charles is in -- I think Lucas earlier on the call mentioned the Permian as one of the sleeping beauties in the Shell portfolio. I think Lake Charles probably is in its own way a sleeping beauty from the Ex-BG portfolio that we are very -- that I'm very, very pleased to have in the portfolio. It is an extremely competitive US LNG project, obviously, brownfield. But the way BG has built this up and designed it and has pulled it together, its first class.

And so it's a very good opportunity to build LNG supply right at the left hand side of the -- low-end side of the cost curve that we will benefit from. So the trick here really is to try and judge when is the LNG market is going to need this volume again. And as you would have seen, if you track this market in the last 18 months, we've really only had one FID that was the new train on Tangguh by BP and most of that LNG is actually going to stay in Indonesia.

But apart from that, it's been dry in the industry and it could remain dry for a bit. And that's not a bad thing, because that's a lot of energy coming into the market as has been noted before on the call. But somewhere in the course of the early 2020s and whether that's 2022 or 2023, it's going to depend more on demand and on supply and there are some good signs on demand and this market is going to rebalance. And inevitably then go short, because supply reaction is always delayed of course.

So the trick is really when you take your best supply projects into an FID to be there when the market needs the volume and is willing to pay good prices for the volume. That is not today, is why my feeling if that would -- and that's been our decision. And so we don't really think this is the right time to take an FID at the moment and also we look of course at the affordability in the Company and we say that's actually quite convenient that we are able to postpone this piece of capital.

But it is certainly a project that I'm very pleased to have in the portfolio, an option that is a good one for us to have and hopefully find the right time to exercise it and bring it into the on-stream portfolio, and we review that periodically.

Thanks, Maarten. Okay, next question.

Alastair Syme, Citi.

Hi Simon and Maarten, can you just talk about your long-term strategic planning, I think you've traditionally done this in the third quarter and I just wanted to confirm (inaudible) exercise again this year and did you change your internalized long-term view around oil and gas markets?

And secondly, this is a very quick question, can you remind us of the stakes at play on (inaudible) disposals? Thank you.

Thanks. Alastair, the first one could be a long one. So I'll keep it short (inaudible). What we do in essence in it's a three-year strategic planning cycle, where we do a full bottom-up in the portfolio once every three years and reaffirm strategic intent, we really did that last year as we're still doing the BG deal. So this year we updated it in an assessment that that in itself have turn-up some questions around gas markets, gas pricing and actually Maarten has pretty much given you the oversight of how we think about those already.

Oil, we've long been of the opinion that demand will peak before supply and that peak may be somewhere between five and 15 years hence and it will be driven by efficiency and substitution more than offsetting the new demand for transport. We still have that view. We still have a view that there will still be a substantive business for us for many decades to come as a result and that also the reason Maarten also has a new energies business in his mandate is that actually new forms of energy used for transport such as gas or electricity or biofuels or hydrogen will actually from part of the future energy system after the transition and therefore even if oil demand declines, its replacements will be in products that we are very well placed to supply one way or the other. So we need to be the energy major of the [2050s] and that underpins our strategic thinking as part of the switch to gas, as part of the work we do in biofuels both now and in the future second gen, third gen and hopefully will be part of how we develop the new energies business overall in the electric or electricity value chain.

[Shale] is a two-part transaction. We sell the shares (inaudible). The first part of that transaction is subject only to completion of the competition review within Japan and it has been our intent to complete that deal when we receive that competition authority approval. The second part of the transaction, the merger is the piece that has created some issues with some of the shareholders of Idemitsu and I can't really comment further on that because that's partly an issue for Showa Shell and Idemitsu to resolve but we are still of the intent to conclude the first part of the deal as and when competition authority approval is received. Cannot give you a date on that, could be this year, could be next year.

In Motiva, we basically agreed a non-binding agreement earlier this year stating how we will split the assets after 17, 18 years together and that is from a 50:50 joint venture. Saudi Aramco will take slightly more of the value. So likely that would lead to some form of -- sort of cash balancing payment when we actually close the deal, closure is expected early next year. Not sure if we've given a specific date. We're working on the final agreement and I can't say any more than that at the moment. It won't complete this year is one thing I can be sure about. So I think that was it. Do we have any more questions? We seem to have run out of questions.

Ladies and gentlemen, this concludes the question-and-answer session. I would now like to hand the call back to Mr. Simon Henry, CFO.

Thank you very much. Well, thanks everybody for calling in. I realize it's been a busy day with two sets of results and more. Thanks for the questions. Pretty good coverage today and some really important issues covered. Hopefully both in the presentation and the answers you can see evidence that the portfolio, both the shale portfolio and the way it now combines with BG has quite some power to perform as we're going forward, power to generate cash and power to deliver the value that we state as when we first did the BG deal.

I keep on needing to repeat, $64 billion acquisition, we are 19 months since announcement, job done, synergies being delivered, value being identified. We know who is delivering it, how it's going to be delivered, two companies together, same cost base as one company. We've done this years ahead of expectation, not our expectation, but the expectation external to the Company and that is really having an impact today now on the underlying financials that you see.

Now, we will be having an Investor Day in New York next week on November 8, actually one week today. Ben, myself, and several other members of the executive team will be in attendance and we really look forward to talking with you face-to-face then and giving you the chance to hear a bit more and ask a few more questions about the substance behind the comments made today and the performance that you see. So thank you for your time today and look forward to seeing you.