Thank you holding ladies and gentlemen. Welcome to the Royal Dutch Shell Q3 Results Announcement Call. There will be a presentation followed by a Q&A session. (Operator Instructions). I would now like to introduce your host, Mr. Simon Henry.

Thank you very much. Ladies and gentlemen a very warm welcome to you all today. We announced our third quarter results earlier today and I’ll take you through them, and of course there will be plenty of time for your questions. However, first, something we must reflect on last week’s tragic event in Moscow. Christophe was a warm, unique and charismatic individual who touched thousands of people in our industry. Thoughtful leadership and the huge impact we have will be sadly missed by us all. Moving on, first, our disclaimer statement. Moving on to the priorities, as results today show we are delivering on the three priorities, we started this year, better financial performance, enhanced capital efficiency and continuing strong project delivery. We aim to grow cash flow through the cycle and at the same time deliver competitive shareholder returns. We’re making good progress with restructuring in North American resource play essentially completing the asset sales program there. And we’re continuing with the cost of the portfolio reductions in all products. As a recent decline in oil prices, is very much path of the inherent volatility in our industry. We planned the strategy around an expectation of those volatility that portfolio needs to be attractive and resilient in a wide range of circumstances. This underlines the importance of our drive to better performance management, to keep a hold on costs and spending, to improve the balance between growth and returns and to improve our capital efficiency. Proceeds from asset sales so far this year totaled almost $12 billion with further disposals ongoing. The new projects are delivering benefits to the bottom line now. Overall production volumes were lower but margins are higher as the strategy of investing in profitable projects with or without equity production pays off. We continue to…

(Operator Instructions). Your first question comes from Lydia Rainforth from Barclays. Please go ahead. Lydia Rainforth – Barclays: Thanks and good afternoon Simon. A couple of questions just if I could. The first one just on the bigger macro environment, I think you’ve always said that you’d be – that you’re very well positioned over Shell with down sort of conditions. I’m just wondering where are you prepared for that gearing levels go to if we stay at this sort of level for little while? And then secondly, and it’s just more on the numbers. In terms of the integrated gas line, given the Repsol acquisition, how much of that actually comes from the upstream Americas these days as opposed to the international partner? Thank you.

Thanks Lydia. The macro, I think I’ve been seeing two or three years that the oil price probably was defined gravity. And that’s perhaps coming through in the way that underlines supply-demand fundamentals would indicate as a moment. The gearing range we say, we would expect to see us through such barriers such volatility is there out of 30% currently 11%, just over 11%. I am well aware that the rating agencies in particular, and quite possibly the equity market feed would get a little nervous if we hit 20%, one of the reasons being the inclusion of balance sheet liabilities as well. And therefore, before we would get nervous another 10% gearing roughly $20 billion of additional net debt that’s equivalent to effectively think about it $30 for a couple of years of the oil price. That’s not a prediction that that’s going to happen but that’s the range at which gearing I think we would need to be looking quite seriously their investment program. The reason we would retain that wide range is fundamentally so we can complete what we’ve started in terms of the capital program without taking value destroying decisions so clearly as we go forward, we’ll be taking a close look at where we think the macro will stay as we look at new investment decisions. But currently the intent is we finish what we started. And so, the second question Lydia of the Repsol? Lydia Rainforth – Barclays: It was, yes, it’s about the proportion of the expected gas business from the Americas?

Just to note that we stated on acquisitions that we thought with a fair wind behind us, we might be able to deliver billion dollars of cash flow from the assets we acquired. And that was aspirational over time after we embedded and practiced, we may well be able to deliver that much this year. That has been a very strong contributor, a very good deal and better than our activities, day-to-day activities almost from week one. The majority of it does show through in the upstream Americas and is then the integrated gas is a combination of the Americas and the as from international fees. I don’t have a figure for that, we actually split it but more than half is in the Americas. That’s the billion dollars is cash flow, not earnings, the earnings is lower because of amortization of the premium. Thanks. Lydia Rainforth – Barclays: Thank you.

Thank you. Your next question comes from Theepan Jothilingam from Nomura. Please go ahead. Theepan Jothilingam – Nomura: Hi Simon, two questions please. Just firstly on, you talked about the deport project for shallow first, you talked about our operator up and the 300,000 plateaus. I was just wondering what the contribution is for assets wherein Q3, and when you might expect to reach plateau? And the second question is just following up on project delivery. Could you give us an update or on Corrib please? Thank you.

Theepan, thank you. The deepwater, four big projects, we’ve got a few smaller ones and some non-operative starting up again as well. So it’s just in the Gulf alone in the U.S. We hit the bottom it’s about 170,000 barrels a day a year or so ago, we were close to 220,000 this quarter so, roughly 50,000 barrels ahead of where we were a year ago. The totality of the deepwater, where in the quarter we were, then this is including outside the Americas, we were at about 286,000 barrels a day in that third quarter. So, we’re getting, we’re closing in on the 300,000. Of course the third quarter had minimal contribution from Gumasol. And in practice, Carmon only started up towards the end of the quarter. Bonga Northwest came on in the quarter. So, still hopefully some legs yet in that portfolio with the new project but it is relatively high decline on the existing assets. So, on balance overall, we’re on track for the totality of the 300,000 in the deepwater activity. Project delivery, Corrib, and that is a forgotten project in some ways but we’re essentially pretty much mechanically complete but we need to start moving into the commissioning phase which means it’s going back to some wells which have been down for quite some time etcetera. So we’re not planning on any contribution really until towards the end of next year. But the tunneling is done and most of the mechanical pieces are all in place. Many thanks Theepan.

Thank you. Next question comes from Thomas Adolff from Credit Suisse. Please go ahead. Thomas Adolff – Credit Suisse: Hi Simon, two questions as well please. For a company like Shell, which is exposed to an essence every type of upstream projects. And I’m aware of what you said earlier on, on strategy and planning. But say, we get to the stage where you have to manage your CapEx slightly differently, which area or areas are the most likely impacted first, is it Shell, exploration your base in terms of work-over and filtrating deferrals of operated projects in essence how is Shell’s portfolio CapEx managed in a slightly low oil price environment? The second one is just a quick one on Bazar (ph) gas it’s a bit of a black book if you can possibly quantify what sort of contribution you expect from the project? Thank you.

Thanks Thomas. Our thoughts on Bazar (ph) gas, that’s you may recall it, essentially price has been wet gas stripping liquids, the dry gas goes back into the effectively the rocky power chain for which Bazar (ph) gas received a fee and can file a liquid. So no equity production but when they’re processing in, getting close to 600 million standard cubic feet of raw gas at the moment, collected from this space of associated gas, it’s reduction of flaring. So it’s doing a great job for the environment as well as the Iraqi power sector, the actual contribution at the moment, relatively small but cash positive. The next question for us is investing and expansion in some of the LPG handling. And so far so good, the operation is very well managed. We’re 5,000 employees there, all Iraqi and working well. Over time, it can be quite a material contributor. And I’m not sure we’re exposed to everything but we certainly do have a diverse portfolio of investment opportunities. And going forward, look at it in different traunches, what are we spending on the big projects, the headline projects, which is only around the third of the total spend. We will complete, finish what we started there. We will think carefully about the timing of big new decisions going forward. But we do as I mentioned in the speech, Appo, Vito, LNG those are some really quite interesting, exciting projects either in Brazil or even the early work there. So, that’s the big project. We have probably not this similar amount going into asset integrity, small project type of activity as well. So the asset integrity comes first, the small project clearly, they are likely to be in practice either attractive or necessary to sustain the operation as it is today. So, while there is some flexibility possible, and there are consequences for cutting that back in the short-term. We then have about a quarter and then the longer-term, which essentially is exploration and the unconventional spend and if you like, pre-FID feasibility or late field work. That is a bit more flexibility, that is something that we take a close look at but not really willing to ease our seat particularly when we’ve made some pretty important choices around portfolio priorities in the unconventional areas. So, we’re not going to jump to any rapid decisions to stop cut or slash anything that in the short-term will only destroy value. Having said that we are not immune to the environment and I would like to think it’s a very constructive discussion of our priorities, phasing. And in this environment, looking again at the supply chain, and the way that we deal with our suppliers, if we’re placing a period of lower revenues. So, it’s not a single outcome that we’re looking for and quite a few levers that we need to balance. Thomas Adolff – Credit Suisse: Okay. Thank you very much.

Thanks Thomas.

Thank you. Our next question comes from Alastair Syme from Citi. Please go ahead sir. Alastair Syme – Citi: Couple of questions. I know, Shell has moved away from talking about individual projects in the past. But can you give us some sort of view on payload governance, such a huge operated component of your growth? And I say that with respect to we’re also aware that, Riyadh and Korea has had issues with other operators that are using Riyadh? And then secondly just looking at the slide 18 which I’m intrigued the portfolio development to 2014, this strikes me about the projects and feed, how few they look to be? And maybe you could just sort of comment on where we stand on brows within that context?

Thanks Alistair. And we’ve moved away from giving specific custom schedule outcomes for projects. We look to talk about that. And on track for budget and schedule at FID in pro-E, but you’re right, the Riyadh is there. We’re about two thirds complete in the mechanical completion. We’re about three years plus or minus a few months depending on events from seeing significant revenues from that project. Those events include the monsoon weather in terms of the winter those from moving the facility out and commissioning. That would be 10 years from original discovery which we think is pretty competitive given the nature of the project. It’s a challenging project but looking good in Riyadh, we were there quite recently to visit and very confident that we’ll have a great project there. On the next wave of projects, the slide only shows the feed decisions this year really, there was quite a few of the project. It’s a big project at the moment that, are three-feet, all of which are operated by others, LNG Canada, Appomattox and Vito in the Gulf. We are pretty much ready to pull the trigger on Bonga Southwest deepwater in Nigeria as well. But that actually needs quite a lot of role of stakeholder support as well. On non-operated projects, remember France is not Shell operated, its Woodside operated. I would have to defer you to Woodside. Clearly it’s an interesting project and would be a very large project, the Shell holding 26% per say. Well, I can’t really add anything to statements made by Woodside. Thanks Alistair. Alastair Syme – Citi: Thank you.

Thank you. Your next question comes from Fred Lucas from JPMorgan. Please go ahead sir. Fred Lucas – JPMorgan: Thank you, good afternoon Simon. Simon, can you run us through what projects you expect to sanction in 2015, and which projects you expect to start-up in 2015? I guess the last of both operated and non-operated as well? Secondly, on upstream depreciation, it’s very difficult to track it with impairments and assets leaving the portfolio. Could you tell us where the run-rate is now for unit depreciation and where you’d expect that to go to in 2015? And if I may, just a quick question around your application to suspend operations in North American Artic, if your request is denied by the Bureau of Safety Environments Enforcement, where does that leave you? Do you see the acreage recycled and having to re-bid for it or do you seize operations there altogether? Thank you.

Thanks Fred, I’ll start with the backend. The application is to expand not suspend, I think it got lost in translation when the NGO sent you a letter (inaudible). The reason for asking for the expansion is pretty clear Macondo and the current litigation which is remember against the DOI not against Shell plus live parts of the earlier litigation and the significant changes in regulation mostly as a result of Macondo as sort of added delays, our events we build justifiably. We can claim were not under our control. In the event that we’re unable to expand, I can’t really speculate on where – why we would be less than those circumstances. But it’s just part of normal practice really looking to expand the leases to enable us to drill when in fact that’s really decisions taken down in Washington that would present actually a drilling to date. Also worth noting that 30 years ago, we went and drilled several wells pretty quickly, no real issues in the theater, it’s not that difficult to drill up there. That was the basis of the original application, the original significant bonuses that were paid back in 2005, 2007. And so, all of that put together is what’s driving position. The clean DD&A, you’re absolutely right, it’s gone up and down. Another fact that it’s there this year and will probably would come down a bit next year as Majnoon with a lot of the cost recovery effectively flows through as DD&A. So, the current clean DD&A is around 3.5 billion upstream both per quarter or 14 for the year. And that will come down a bit with Majnoon reaching sort of full cost recovery roughly at the end of this year. But we’ll go back up a bit of the effectively…

Well, the headline growth that would be negative, because of the impact of divestments, which – just to be clear, because I don’t give the exact figures. We’re already down close to 300,000 but now in totality it’s 244,000 down in Q3 alone from divestments and the Abu Dhabi license expiry, 76,000 from divestments for rest of Abu Dhabi. And the full year impact of divestments already made and the license expiry for next year is about 350,000 barrels a day. And of course we have ongoing the Nigerian divestment program which has a capacity of 80,000 to 100,000 Shell share of the actual production at the moment is a bit less than that. So, all of those flowing through, will have quite an impact on volumes. The underlying volume delivery will depend a bit most likely on the rate of progress on the unconventional. So, the underlying decline at the moment is actually about 3% year-on-year, which we’re looking to offset. So, all of those factors combine, production will be lower and we’ll aim to keep the unit margins up notwithstanding the movement in the oil price and very much a focus on the dollars and not the volumes. Fred Lucas – JPMorgan: Thanks, very helpful. And just on the project sanctions interested by your components on potential supply chain efficiency, I was just wondering if there is, and what sanctions you would expect and whether it would actually make tactical sense to defer a few?

Well, you might be right on the latter. And let’s say about the big ones that most likely we have Appomattox which is 800 million barrel now in Gulf of Mexico, deepwater, potential chemicals plant in Pennsylvania, let’s not forget the mainstream, a couple of smaller ones as well in Singapore and Rotterdam in refining terms as well, but small relatively quick payback few hundred million. And the LNG Canada, maybe not next year but let’s see quite where we can get to. I can’t really comment on some of the non-operated such or browser or body, I think in the environment they may get pushed further out. Fred Lucas – JPMorgan: All right. That’s very helpful. Thanks Simon.

Cheers Fred.

Thank you. Next question comes from (inaudible). Please go ahead. I do beg your pardon, it comes from Ian Reid of BMO. Iain Reid – BMO: Hi there, hi Simon.

Yes. Iain Reid – BMO: Just listening to what you’re saying about production and just kind of taking a step back. Not very long ago but you were sitting there or standing there I think and telling us it’s about 4 million barrels a day, I know you don’t target production anymore. But you’re now down to about 2.8 million barrels a day and guiding lower. And I’m just wondering for a company the size of Shell, what sort of critical math you think you need to have in terms of volumes and not to support all the earnings, it’s that’s to support the current infrastructure in terms of people, project names etcetera, because the way you’re going, you’re going from second of the industry in terms of volumes to this continues something like fifth. I’m just wondering how significantly would look at this in terms of shrinking this business quite so radically?

Thanks. I think you find whenever I talked about 4 million, it was followed by the words this is a proxy for the growth you can expect in the business as a result of the high level of investment program. The simple translation of the growth not sort of to say volume driven, decision making that minds therefore and CEO if that’s how we’re focused on. The growth will be less than that. I think it’s fair to say there has been a bigger divestment program. And there have been one or two highly public delays in delivery such as Kashagan or Gogan. So, they – all things being told there is still an expectation of growth obviously back out into the latter part of the decade. And while there is some linkage to volumes, and we think about it is the robustness, the resilience and the level of persistence and delivery of cash flow growth. So, our targets are cash flow growth, return on capital and as an outcome of those, ultimately the free cash flow that drives dividend sustainability and hopefully growth. And essentially optionality within the strategy if you’re not delivering that free cash flow then we’ll always be victim of circumstance. So that’s what we are looking to get the right balance around. And the production that delivers that ultimately is just a bit of an ongoing and incidental but if it’s something we target in its own right, we’ll know we can get the wrong outcome. And just anecdotally of course, just comparing the Abu Dhabi and with the Gulf of Mexico in fact, few thousand barrels, tens of thousands is replacing a 160,000. And with – and that’s a positive impact on the bottom line. And Repsol, Bazar (ph) gas likewise. So that’s how we think about it, it’s really the certainty of the underlying growth. And I think you’ll find in terms of where the cash flow generation is. We very much, still our second and over time, let’s hum them down. Iain Reid – BMO: Okay. I just had one quick follow-up. On the refining impact you’ve given, does that include the potential shutdown of a train in Singapore?

And your refining impact of 6% I think is just the divestment and yes, we’re looking at the distillation capacity in certain parts of the world including Singapore. There are three distillation units in Singapore i.e. you may be aware. Iain Reid – BMO: Okay. So this doesn’t include that?

Well, we’ve not made final decisions but we’re certainly looking at the – I’ll tell you, we did certainly look too closely basically planting in furnace for lubricants, as a means of improving the flexibility of crude supply into the refinery. And we’re already seeing early benefits from the lower crude cost that’s enabling demand for fuel throughout the value chain. Iain Reid – BMO: Okay. Could I just ask one final thing? Are you bidding for the renewal of the Abu Dhabi license?

We wanted the companies that, is interested, yes. We’ve all made offers and it’s at the moment is with the government. Iain Reid – BMO: Thanks very much Simon.

Thanks.

Thank you. Your next question comes from Martijn Rats from Morgan Stanley. Please go ahead, sir. Martijn Rats – Morgan Stanley: Yes, just two short ones. I wanted to ask about the downstream results, which of course was a lot stronger than before and also stronger than at least we had forecasted. This of course was at the benchmark marked a margin but also underlying. And I was just wondering if you could say a bit about what part of the result sort of uplift is the environment versus the structural changes that you’re putting in place? And secondly just a small one to clarify, but year-to-date CapEx has been running a bit below this sort of guidance you’ve given for the full year. But then typically in the past, in the fourth quarter we got point of sort of large amount of CapEx. And this is, I just wanted to ask you if that is a profile that we should expect this year as well?

Okay, I’ll deal with the second one first Martijn. The intent or expectation of the CapEx is $37 billion of which $2 million relative to completion of acquisitions from previous year or minor acreage during ‘14. So, interestingly we’re bang on target with $35 million organic and $2 million of acquisitions. So, it looks like, and the $2 million of course is not equally phased. So the run rate is pretty much on target, much closer than we usually are, for the expectation for a given year. The downstream result, we’re up by $900 million, we’re up as year-to-date quite significantly. It’s not easy to be very specific here about environment versus actual underlying structural improvement because ultimately one of the improvements is capturing the opportunities from a volatile environment. But it’s about 50-50 Martijn. The actual improvement, are a combination of refinery operational performance has been pretty good. Our utilization has been higher as well as availability and that’s in part because of effectively taking advantage of margin opportunities that were there by looking at the pole field values chain, so the true traders, the supply traders, remember we trade as much product out into the market as we market out into the market, 3 million barrels a day roughly each. And so, and we’ve taken cost out and we’ve upgraded the marketing product mix, higher proportion or better unit margin, high proportion of premium products so B-power, Shell Helix and just focusing on where we’re getting the best bank for the buck in the market. So, all of those have been levers that’s essentially barricades (ph) itself year and half ago and John is now executing well and things will benefit. But certainly we see first of all its hard work everywhere, every day by lot of people. And secondly there is quite a lot more potential out there for us. So, we’re in the middle of delivering it. Martijn Rats – Morgan Stanley: All right. Thank you.

Thanks.

Thank you. Your next question comes from Lucas Herrmann from Deutsche Bank. Please go ahead. Thank you Mr. Herrmann, your line is open. Lucas Herrmann – Deutsche Bank: Sorry, Simon, good afternoon. Thanks very much for the opportunity. Couple if I might. Just going back to growth, but maybe changing the dynamic slightly and thinking about a five year view, you seem the perfect person to ask. The objective is clearly to improve return or amongst what your objective is, one is clearly to improve return on capital employed at the present time? How do you see the capital base growing over the next five years on the assumption that if my returns are improving and my capital is improving, I should be able to, I should expect now an improvement in profitability and cash flow. So rather than talking barrels Simon, could talk capital?

Did you have another question or? Lucas Herrmann – Deutsche Bank: Yes, no, the second question which I’ll cover to the second question is very simply exploration charge what should we be expecting for Q4? Last year was what 1.7 billion negative which was a very big drag on the profitability of the business? What are you anticipating as we move forward, what guidance can you give us? I’d like to come back to you on Nigeria gain as well if I might afterwards.

Okay, thanks Lucas. The growth that was one of clever ways I’ve heard of trying to extract a target from me. The CapEx is running at a higher level on the DD&A, fairly clearly. So we’re growing 7% of capital employed over the year, kind of the level of investment. Then if we continue that will likely continue. When we talked about return on capital improvement, to a competitive position we’re not necessarily an industry leading position because we think there is a trade-off between growth and returns. And obviously, the actual return we achieve is to an extent oil price length. And are we happy with 10% returns at $110, no of course not. And so, we would expect to improve the returns by a few percentage points and not necessarily deliver 20% returns as $110. Lucas Herrmann – Deutsche Bank: Sure. I guess, I’m more interested in your capital base Simon, I mean, you’ve got a view on what you’re going to be divesting you put up, if you want what you’re going to be investing, you have a base oil price, you must be able to come up with some indication of what kind of capital growth one will see on a five-year view?

6% to 7% a year is not a bad going rate that is about 30% above where we are to 20% at the moment. I think it certainly is going to probably come back in the Q4 because the divestment program paradoxically doesn’t have a major impact on capital employed. And the FX movements in the back end of the quarter I don’t see much impact as the divestment program. So, it is something that we think about not necessarily in totality for Shell but for the individual strategic themes that we feel today. So if I said downstream, I would not expect that to increase but depends on what choice we make with chemicals. It may at least stay at similar levels. I expect integrated gas and deepwater in particular to grow strongly. The rest of the portfolio, well let’s see. There will be choices based in part on capital and in part on returns but very much also in part of what’s the ongoing investment commitments in the potential growth. And exploration charges Q4, you’re absolutely right, it was $1.7 billion, it was largely driven high exploration write-offs which importantly don’t come along regularly. I could say fortunately this year they haven’t come along at all really. And we have more than our fair share of them last year. The ongoing rate is about $800 million to $900 million per quarter with a small number of contributions from write-off. We have couple of wells going down now that I think there are one or two that may place it into the write off. I don’t actually have a feel yet for the success rate likely in the quarter on which wells will reach TD. In fact several of the big wells at the moment won’t reach TD until first quarter. So, there is not many, have a big exposure in Q4 and may run over into 2015. So, we would hope that the charge was a bit lower year-on-year Q4 to Q4. But it’s just too soon to say. And I can’t give you any more specifics than that I’m afraid. Lucas Herrmann – Deutsche Bank: Okay. Maybe you could encourage JJ sales, let us know if it’s going to be materially above $0.8 billion come the start of the next quarter?

What we’ll try and do is be clear about which well achieved what outcome. Please bear with us though because if we’re not the operator that’s not within our get. Lucas Herrmann – Deutsche Bank: Yes. I’m sorry Simon, just going back to Nigeria, I didn’t quite understand or catch the comments you made around the level of barrels that you were affectively divesting? And also, can you just explain to me what is actually – I mean the proceeds that have been talked about. Are those just proceeds that relate to your interest, totals interest and E&I’s interest? I mean, in short, the news wise has been carrying a number of around $5 billion your onshore divestments, I don’t know whether that number is right or wrong. But what I’d like to know is whether that number is just associated with the IOC’s interesting or whether NMPC is in there as well?

I’m sure, the Greek as confusing because actually we said very little about this, just about everybody else has, buyers, sellers, government and banks. So what the facts are we have four onshore and one related pipeline activity. All the activity is basically oil associated with an MB Creek trunk line environment evacuated through the Bonny Oil Terminal. The potential production in that space is 80,000 to 100,000 barrels a day, Shell’s share, about 30% of it. And current production is more like 30% to 40%, because remember this is the area that is very subject to sabotage and theft. So, it’s a big area, it’s got big reserves. And the figure of $5 billion has been quoted strangely it’s approximately correct. But that’s for the Shell E&I in total share and NMPC is not selling, and in fact that actually has preemption right on the sales, where they have to choose to exercise that right. We have signed FPAs for all four licenses and the pipelines, so five FPAs. The total proceeds to Shell are around $3 billion. But I can’t give either specific numbers for specific transactions, nor can I give any indication of when we expect to conclude because all remain subject to ministerial support and approval within Nigeria. So, we can really only update as the transactions are signed off and the cash changes hand. So, we understand the offer deciding for the other IOCs. We have no reason to expect they won’t accept the offer whether to confirm that you probably need to talk to is total in E&I as I think you all know. We have 30% total spend E&I five. Lucas Herrmann – Deutsche Bank: Yes. And where does that leave you with the rest of your onshore by the way which isn’t gas, because I mean, my impression would be that the prices you’re able to command seem pretty attractive relative to the troubles that the positions entail?

Fundamentally the remaining piece that is not gas is just to the east of blocks that we’re selling it includes the well-known Agony Block, although we don’t operate within that particular area. And it’s associated with the Trans-Nigeria pipeline. So there is another pipeline system associated with it. Now in this particular process, this block is not actually included. And that doesn’t mean I wouldn’t exclude necessarily future consideration but it’s one step at a time. To the west of these blocks, is essentially the gas producing acreage which we and what we are investing in at the moment to grow the production there and ensure that both domestic gas and production growth and that we keep the LNG will fall and we also have some shallow water offshore blocks which are operated by the joint venture as well. Now, it’s still a major operation in addition to gas and deep water. And hopefully that gives you a feel. A lot of the oil reserves are associated with the blocks that are for sale and that one particular big block in the Trans-Nigeria pipeline area. Lucas Herrmann – Deutsche Bank: Simon, that’s great. Thank you. I’ll leave it there.

Sure. Thanks Lucas.

Thank you. Your next question comes from Mr. Jon Rigby from UBS. Please go ahead. Jon Rigby – UBS: Hi Simon. Can I ask just one question, just one clarification? Can you just update on what you’re thinking around LNG Canada, I noticed earlier this week a competitor project was sort of being backed off a little bit. And I guess there is a process where you need projects to get shaken out rather like we saw in Australia. So, could you sort of characterize where you stand on this project and where you think it is in terms of its maturation? And then just going back to the discussion around Nigeria and the onshore, if I follow what you’re saying look at what SPDC was producing over the quarter this year, I think 100,000 barrels a day at the first two quarters and a little lower in the second and third. Are you effectively saying that the remaining liquids production in SPDC to you will be of the order for about 60,000 to 70,000 barrels a day liquids?

Yes. Well, the last question is easy. Yes. Jon Rigby – UBS: Right. Forgive me, but that’s mainly EA is it?

It does actually include EA yes you’re correct, which is shallow water offshore for those that are not that familiar. And the results so far, the growth potential shallow water offshore by the way, but we’re not growing there at the moment. And LNG Canada, I know there were 17 projects applied for permission to export its even more crowded than the Gulf of Mexico at the moment in terms of notional projects. If all of the North American projects went ahead by the way, it would be 400 million tons of export capacity which compares to today’s time market of 250. We don’t think they’re all going to go ahead, let’s put it that way. Most of these projects happen, takes a quite a long time, technically the first in a Greenfield environment at least part of it Greenfield to bring together all the stakeholders. We have been working extremely hard for the past two to three years to ensure that we have not only the land to build which is clearly in place now in Kitimat, it’s a Brownfield site, not Greenfield so we’re already over quite a lot of the hurdles in more of these environmentally sensitive area. We have great partners both for the midstream but also the upstream gas production in the downstream LNG market, in our Chinese, Japanese and Korean partners. We have the best pipeline operator Trans-Canada contracted to build the pipeline from the Montney area and our Graham Birch Gas development. So, all the pieces of the value chain are in place. We’ve been working very hard also with the First Nations tribes, there were 28, 29 tribes or people that are either at one end the physical value chain as well. And last but certainly not least, the British Columbian government,…

So, if we’re in those two trains, third or fourth train, there is certainly room and there is certainly gas available for that end and maybe more. Consolidation, well, that’s perhaps for the future but we have learned both sides of Australia that that’s probably a good idea. Jon Rigby – UBS: I was going to say so you think industry can avoid the fiasco of Queensland?

Well, one would hope so, yes. Jon Rigby – UBS: Right, okay.

What I cannot guarantee to avoid is on behalf of the industry Jon. Jon Rigby – UBS: Right. Thanks Simon.

Thank you. Your next question comes from Irene Himona from SG. Please go ahead. Irene Himona – SG: Thank you, hello Simon. Two questions if I may. Firstly upstream and Majnoon in Iraq. Can you talk about the earnings impact and whether you’re actually receiving any cash, so are they paying invoices? And secondly in the downstream, obviously you mentioned a drop half the improvement was let’s say self-held. How much of that half was Motiva please? Thank you.

Thanks Irene, 140 million the answer to the second question, of which again is roughly half and half and although in that case probably it’s more like 60-40 environment and operation. And Majnoon, good question. We are one year into and their production was remuneration. We had to meet the original first commercial production target of 175,000 barrels a day. Remember this is the first Greenfield bid or license that was on our end. The previous fields West Canada, actually they were Brownfield. So, we needed to take time to set up some of it, the processes and the relationships, secure the government on cost recovery for example for our Greenfield which one of the reasons we’ve been a bit late to hit the first commercial production. But having hit it, we’re now averaging to 10,000 barrels a day there, that’s not our share that’s the 100%. And we are recovering our cash pretty quickly. By the end of this year we expect give or take a few weeks to recover the essential capital outlay. That cash coming in is in this year’s CFFO. And as soon as we’ve recovered, we dropped back to just receiving the remuneration fee which is quite a bit smaller. And the actual overall earnings impact for Majnoon is pretty low. And fundamentally build up a big asset then you depreciate it quickly and the asset equals to cost recovery bank. Now the CFFO has been good this year, clearly over the back end of last year, this year, maybe a little bit will creep into next year. You’re talking a couple of billion also coming back in. And that will slow in early 2015. We have not yet agreed a full field development, either what the concept would be and the objective and the production level. If and when we do so, that would effectively add CapEx, that is recovered typically within three months. And we have a very high cost recovery rate, close to 100%. Having taken a lot of time upfront to get agreement and build the levels of trust that are required in a new environment. So, it’s a bit like Canada LNG, we think that in the longer term the upfront investment in stakeholders, the relationships it does pay off. We also have of course the Bazar (ph) gas which is contributing. It actually contributes a bit more than Majnoon even at the moment and certainly in the longer term absence a decision to grow Majnoon will do better. I think that covers Irene. Irene Himona – SG: Thanks very much.

We’ll move on to the next question please.

The next question comes from Richard Griffith from Canaccord Genuity. Please go ahead. Richard Griffith – Canaccord Genuity: Good afternoon Simon. I was intrigued by your comments about your liquids rich shale and whether you might or might not take decisions next year on the back of where we are on the oil price. And I was just wondering what do you see as the cash breakeven for LRS from your point of view but also from the industry point of view in North America and also if possible by basin?

I wish I knew Richards the answer, to answer on those things that will drive the decisions. Well, that’s because it’s not independent of the oil price. The costs do tend to adjust but maybe not enough. We’re into the middle to late stages of appraisal in both the Permian and West Canada. We’re seeing some great wells we’ve had quite significant number of wells, 1,000 barrel plus initial production rate and which is when you’re talking sweet spot something that is going to work. Clearly, 1,000 barrels a day and multiple million dollars of barrels when you’re only spending today somewhere between $5 million and $10 million to drill and complete a well, then you’re going to do okay. But what you need to know is what’s the average going to be when you decide to drill 100 or 200 wells across a particular rollout where you’re building infrastructure etcetera. That’s where it’s pleasing to say we’re not that far away but we may not pull the trigger on a development what we call a common value area sooner rather than later as we take a view on what the oil price actually is. Richard Griffith – Canaccord Genuity: Okay.

And that’s Shell’s perspective. We would hope to be able to develop oil prices with a breakeven below today’s level. I doubt we would take a positive decision if we couldn’t do that. For the industry it’s a great question. We’re watching what others say. People who have more direct experience but actually the thing that is of interest to others, the fact that so much of the drilling to date has been financed by say capital markets or the banks $250 billion or so that we can see has been provided by debt or from debt providers into that industry and very little the drilling has been done to the finance from only cash flows. And the way that one plays out with lower oil prices will be interesting to watch. Richard Griffith – Canaccord Genuity: Okay, good. That was a sort of backdrop to my curiosity. Just one other thing, just a confirmation, the decline rate on those wells is up sort of about 80%, is that right per annum?

Well, the first year, yes, not the second. Richard Griffith – Canaccord Genuity: Yes, yes, sorry, the first year, sorry, apologies yes.

Yes. They tend to it’s not an exponential decline. They tend to come down and then you get relatively stable but comparatively low. So yes, that’s one reason we haven’t gone forward. We got wells at initial production what we don’t have is where do they stabilize out at. Richard Griffith – Canaccord Genuity: Yes, okay, all right. Thank you.

Okay, thanks. Next question.

The next question comes from Christopher Kuplent from Bank of America Merrill Lynch. Please go ahead. Christopher Kuplent – Bank of America Merrill Lynch: Good afternoon. Simon, I just wanted to ask you about dividend growth. You’ve got this $30 billion or more than $30 billion number in your press release so you had that for some time now for this year and next year. I don’t know whether my calculations are right but I think you can get there without having to raise the $0.47 quarterly rate. Does that mean you’re sort of leaving yourself a little bit of flexibility depending on CapEx budgets, oil prices, how do we think about that more than $30 billion becoming $35 billion over the next few years? Thanks.

Good question, Chris. I need to remain enigmatic about dividend growth because it is a decision from the board. What we’ve said is we grow, or we aim for a strategy that enables sustainable growth in the dividend through the business cycle. We’ve already demonstrated in the past five years, that doesn’t mean the growth every year. I think your figures are pretty accurate but I wouldn’t over interpret the figures themselves, there is a little bit of judgment as well as the specific outcome. Clearly, we grow in-line with underlying growth in earnings and cash flow. But we have to look at the balance sheet and we have to look at the oil price environment as we find it rather than we might hope it to be. And we’ll have that discussion at the board in January. Christopher Kuplent – Bank of America Merrill Lynch: Okay, thanks. That’s great, Simon. If I could just one quick question for clarification, can you give us a delta in terms of CapEx budget for Alaska, whether you go ahead or not? Thanks.

Thanks. Unfortunately the late reliever decision is to whether we go ahead or not. The small of the delta for next year, you may recall we need a smaller margin, something like just under 30 vessels to accompany the rigs. And we must take two rigs out because we have to have a standby rig available for relief. This goes back to earlier questions I’ve taken on Alaska. And so, if we – as of today, so no, we’re not going to drill next year, we would still have quite significant outgoings next year because both the rigs and some of those – some of that equipment is committed. So we’d only save a few hundred million. Christopher Kuplent – Bank of America Merrill Lynch: Great, thank you.

Thank you. Your next question comes from Neill Morton from Investec. Please go ahead. Neill Morton – Investec: Thank you. Good afternoon, Simon. I have couple of questions please. Firstly, on chemicals, you just split out the result between the U.S. and Europe (ph) no longer and clearly the U.S. is doing very well. Just wondering whether you talk about your chemical portfolio x the U.S? And then, just secondly on Abu Dhabi, it’s held up by both you and others that are poster child for this value versus volume mantra. And yet everyone seems to fighting to get back in. I’m little bit perplexed. The point is that, is it simply relationship issue? Thank you.

Thanks Neill. Chemicals outside the U.S, I mean, you’re right, the U.S. business is doing well basically because of local feedstock. The business recently outside the U.S. is taking a bit of an up-tick because now the prices have fallen partly linked to crude and partly because demand well, hasn’t fallen but it’s also not as strong as we might have hoped so the rest of the margin out there to play with. So, both Europe and Asia-Pacific have made money but it’s not as stronger performance as the Americas. The Europe, I have to highlight the Nordic (ph) incidents, two incidents where we will take a hit in the fourth quarter there and that could persist into 2015. We just do not know yet which units we can bring back and when we can bring them back. So, the European performance will certainly take quite a hit in the coming quarters. In general, the chemical industry is one in which first of all, there is pretty strong growth globally there is a lot of growth in supply as well. But in certain areas if you have either a location, a technology or a cost advantage, it can be very attractive. And that’s why we have been looking at a variety of chemical opportunities including the one in Pennsylvania referred to earlier as a means of taking advantage of being in the right place with the right feedstock and access to the right market. And some of those could be also outside North America. And Abu Dhabi, interesting, we’re clearly interested in any opportunity where we invest in dollar, we return more than a dollar and the risk associated with that is acceptable. But then we come back and we actually countrywide because clearly adding up even the future projects,…

Well, in theory yes, in practice, we’ve only changed it in Q1. Neill Morton – Investec: In recent year?

The board actually considers the dividend every quarter by definition including yesterday for today. It’s unlikely to change in that context, whether it changes in terms of the outcomes, i.e. we move away from just announcing in the first quarter, related to be seen. Neill Morton – Investec: Fine, okay.

Okay, thanks Neill. Next question.

Next question comes from (inaudible) from ING. Please go ahead.

Hi, Simon, from ING, (inaudible). Two questions, one is of course with regards to the divestment program. You’re progressing so fast now. I am considering to, raise the target there given the fact that you have $50 billion for 2015 or is that the end of the low hanging fruit now? And the second question is on Alaska, we heard some environmental players saying that you were trying to get your license which in my view is quite logical. Are you progressing there or is there something as stand still at this moment in the discussion with the government on the license?

Okay. Divestments, we’ve done $12 billion, you’re correct. Progressing perhaps a little bit quicker than we expected against the $15 billion two-year target. We have in progress and still to conclude the MLP is effectively $1 billion. We have conclusion of the Haynesville onshore gas assets which is another $1 billion and we have the Nigerian field which is about $3 billion. So that $5 billion in progress plus a couple of smaller ones. So, I would hope just from that portfolio we can get to the $15 billion. Having said that we are now going forward looking at a much more difficult environment to divest those goods that we have to move quickly and achieve good prices. We are seeing some challenges in one or two smaller deals that we were looking at as to whether the buyers can finance and take to its conclusion the deal. And I think you’d probably be aware that the Woodside, the second phase of the Woodside deal didn’t happen back in August because the shareholders were to begin that and they actual Woodside share price has fallen quite a lot since then. So, our appetite to resurrect may have declined. So, looking forward it may not be these (inaudible) we would have delivered what we said we would deliver anyway I expect. On Alaska, yes, of course we’re trying to extend the license and the asset is entirely normal to do so. Bearing in mind the events that would transpire since we took the licenses. At the moment we are planning and hoping to drill next year but we have not taken a decision to do so because it will depend both on ongoing litigation which is against the U.S. government not Shell. And regulatory permits from the government to Shell that would enable us to drill. I cannot say when we will get clarity but we do not yet have clarity and we retail, we currently retail the ability and the right to not drill next year. Thanks Qurram (ph).

Thank you.

Next question please.

Your next question comes from Oswald Clint from Sanford Bernstein. Please go ahead. Oswald Clint – Sanford Bernstein: Hi, thank you, Simon, hi. Just the first question maybe on the upstream per barrel kind of earnings. Good to see America is picking back up again. But could you just talk about Europe in terms of net income per barrels, seems to be deviating away from the rest of the regions over the past four or five quarters. Is that just the oil barrels falling out of the mix or is there something else happening there? And my second question was maybe more macro, just in terms of your oil products, sales volumes a little bit lighter in the third quarter after being up strongly first quarter, second quarter. Is that weakness just aligned with the kind of global demand slowdown we saw in the third quarter? And any indications what you’re seeing so far in the fourth quarter? Thank you.

Thanks Oswald. By and large, it’s aligned with demand on the second question but we also sold Australia so we lose Australian volumes. And the earnings per barrel of oil equivalent in Europe, well, quite a lot of what we do in Europe is gas, so we’re seeing weaker Europe in gas prices, partly because it’s been so warm. And we’re seeing a decline in the unit margins in Denmark which is probably higher costs, we obviously we’re now seeing the oil price coming down. And I think we’ve spoken before about challenges on the operational performance in the United Kingdom, particularly on the central North sea assets where asset integrity spend, maintenance cost, and decline in production or at the very least the availability, the reliability of production have all been challenges. So it’s a combination of all those factors in Europe. And I think that probably is all I can say about that without speculating further. Thanks Oswald. Next question.

The next question comes from (inaudible). Please go ahead.

Hi Simon, thanks very much for the extent of answering all the questions. I have one major and one follow-up question. Major question is that gas pricing, I believe the spot prices parts is about $13, you’re up $6. In the past you once said that you had about 60% in contract and 40% on support. Is this still actual, and how are you looking to going forward with those firm and larger spots to wait for better contract prices in the future when prices would go up again? That’s the first question. And a small rotary question is LNG volumes went up 16% mainly Repsol, what’s the figure without Repsol, what’s the autonomous growth in LNG volumes?

I don’t have a specific number on the second question although there is some growth because Nigeria LNG suffered operational challenges last year. And most LNG plants were unfold remember that it’s quite difficult to grow other than buying, the buying or building. The gas pricing, you’re about right in terms of where spot prices have been. It picks up a bit in Europe now than, $9 or so in U.K. and B.P. We and the whole industry has shifted progressively in Europe in particular towards a most grades proportion that is spot mainly usually a combination of the hub price and not just the U.K. but Anthrop or elsewhere. So, we’re doing better than the $6 and then the realized price is probably closer to the $9 at the moment. But there are few new long-term gas contracts that is directly and solely oil pricing, quite often there is a bit of a mix. Asia-Pacific, I mean, fundamentally our LNG, 90% or more of the volumes are on long-term contract which are all price linked, one way or another. And it was at 70% of the actual contracts of those contracts themselves are directly linked to oil. So the majority of our LNG business and probably around 40% of our gas in total have some kind of oil price linkage. I can’t really be too much more specific on that because there is a lot of moving parts out there at the moment. And in particularly in Europe, the evolution of the market has certainly been one way and the majority will not be solely oil linked going forward.

Right, thank you. Of course, indeed I was referring to the shifting landscape in special view of the well let’s say the rumors of the price as the Chinese pay for the Russian gas more in the order of $10 or $11. So, I was wondering where the clients indeed are sort of trying to get away from long-term contracts and preferring the actual lower prices?

As most of the long-term customers, remember that doesn’t include very many in Europe. And so, Asia-Pacific, they’re looking for a mix of pricing basis, a little bit of Henry Hub, not sure about Russian border and some oil price linkage but also with some kind of S-curve in there as well to protect against both extremes at the bottom and the top of the price curve. So, it is complex and price isn’t the only part of the negotiation as well. The Russia, China gas price negotiations has really doesn’t have an impact on China and Russia, that’s not really impacting over into the rest of the market at the moment. Okay, thanks Bert. I think we have one last question.

Thank you. Next question comes from Manish Kapadia from PPH. Please go ahead. Manish Kapadia – PPH: Good afternoon, couple of questions from me as well. Your – if I’m right your reported exploration and appraisal spend in 2012, 2013 was around $8.5 billion. And I think guidance for 2014 is around $7 billion. Just wondering are you going to be at that kind of $7 billion mark in 2014? And kind of looking at the portfolio going forward…?

Lost you Manish.

One moment.

Thank you. We’re trying to reconnect. Let me confirm on the ‘13 and ‘14 figures. I think you quoted probably from our annual report where in accounting convention terms quite a bit of what we regard as development spend is actually accounted for as exploration. So our real exploration spend of $7 billion is a combination of three conventional, somewhere between $0.5 billion and $1 billion in Alaska and the rest is in unconventional activities basically Shale in North America, Argentina and China. So, the $7 billion was the target for what we call real exploration appraisal activity for both 2013 and 2014. And that is about the level at which we’re spending. In ‘14, it’s probably shifted more to conventional than unconventional and we’ve been having quite some success with the drilling as a result. We’ve not given any figures for ‘15 but reflecting an earlier question that is one of the few areas at which we retain some or be it limited flexibility for 2015.

Thank you Manish. Your line is open. Please carry on. Manish Kapadia – PPH: Thanks. I think that answered that question. My second question was related to this oil price environment, I was wondering if you believe that buying back shares is still better value than buying into say other assets or companies in this market given you’re seeing this best pricing and it also seems like consensus that a supply market you mentioned yourself that it’s a lot more difficult to get disposals away. So is it, is buying into assets a better alternative than buying into shares with money?

That’s like equity market, not easy to catch a falling knife. That moves from a sellers’ market to a buyers’ market but not smoothly or overnight. There is a period where buyers and sellers look at each other and say who blinks first. We’re probably in that period at the moment where the sellers haven’t got desperate enough and the buyers who have cash which does include us certainly aren’t going to jump in and try and catch that knife. And so, well, let’s see where it goes. Buying back our shares we said, we would offset number of shares that have been issued in the script, cumulatively that equates roughly speaking to the $7 billion to $8 billion buyback over ‘14, ‘15. Lower oil price makes I would suggest cheaper as well, but doesn’t affect our view of the inherent value either of course. So as long as our own shares are offering an attractive alternative to buying assets or other people’s equity, then it will be one of the choices we look at. But of course always in the broader framework of that what cash is available and how do we create most value for the shareholder balancing our returns growth in the financial, the balance sheet as it is today. So, good point to end on. I think we’ve now done. Thank you very much. Thank you everybody for questions. It was quite a thorough examination of the situation and the results. I thank you for that and the interest that you’ve shown. And thanks for joining the call. And this fourth quarter results are scheduled to be announced on 29 January 2015. And of course Ben will join me then to talk to you. Thank you and have a good day.

Thank you. That concludes the Royal Dutch Shell Q3 results announcement call. Thank you for participating. You may now disconnect.