Shell plc (SHEL) Q1 2013 Earnings Report, Transcript and Summary

Welcome to the Royal Dutch Shell Q1 Results Announcement Call. There will be a presentation followed by a question-and-answer session. (Operator Instructions) I’d like to introduce you to your host, Mr. Simon Henry.

Thank you very much, Tim. Welcome to Royal Dutch Shell First Quarter 2013 Results Presentation. Let me give you a run through on the quarter and I am sure there will be plenty of time to take all your questions. First of all, I’d like to share the cautionary statement. And while we have this on the screen, I am sure you’ve seen the announcement this morning that our Chief Executive, Peter Voser has decided to retire in the first half of 2014 and the Board is now started to look for his successor. I just like to say here how much I’ve enjoyed working with Peter over the last 17 years as a colleague and a friend. And of course we’ll continue to do so over the rest of his time here at Shell. Let me move to the results. Start with another cautionary statement you’ll heard before quarterly results are important whether they are good or bad. But they are only a snap shot of performance in the volatile industry, where we in Shell are implementing a long-term strategy much longer than three months. The first quarter earnings excluding identified items was $7.5 billion and the earnings per share were up 2% against Q1 2012. We are investing for profitable growth while maintaining simultaneously strong capital discipline. We’re developing at the moment in 13 new projects and maturing the series of further opportunities for future investment. So far this year we’ve seen the growth impact of recent start-ups with underlying volumes up 2%, and we’ve taken four additional final investment decisions during the quarter with new investments enhanced in petrochemicals in Singapore and deep-water in Nigeria. And then LNG for transport capacity in the North America, they should all add new value for shareholders. We’re managing the portfolio…

Thank you. (Operator Instructions) The first question comes from Theepan Jothilingam from Nomura. Please go ahead with your question. Theepan Jothilingam – Nomura International Plc: Simon, good afternoon, thanks for taking the question.

Good afternoon. Theepan Jothilingam – Nomura International Plc: Just comeback to Australia, could you just talk about the other options still in the Shell portfolio particularly around Arrow LNG and also the stake in Woodside on the later, how you think that sort of adds value to the Shell group. Secondly, just on CEO succession, I know Pete is on the (inaudible) I wanted to know whether the Board of Management had good line of sight on Peter’s intentions to step down whether assuming you known to quite sometime. Secondly, whether the internal processes started and whether you have will be part of that process. Thank you.

Theepan many things, Australia was other options, we’re just a reminder the building in Gorgon, we’re a small shareholder in Wheatstone and the Prelude project are taking nice shape of floater in Korea. They’re already engaged in quite significant development. The Arrow joint venture 50-50 Shell, PetroChina is developing the upstream looking potentially early sale of ramp up gas to domestic or export customers. We’re preparing oil progressing in parallel both the green field LNG option and potential cooperation with the existing project, the three projects under construction there. We deliberately delayed our on LNG project because of cost inflation. And, three projects ongoing in a country which is basically short of well, you can say what the underlying impact is on the project. We’re not in any particular hurry to make a final decision we want to get the economic trial. We also have other floating LNG options we’ve talked about Sunrise previously. We have other discoveries on the Exmouth or the outer Exmouth Shell. And in even shelve we still doing exploration, we’ve got big well going down Shell only 100% at the moment, very significant gas province and that is important for us that we develop at the right project, at the right economics, at the right time in terms of cost. But, Australia remains an attractive country in which to do business for LNG. Woodside, as a result of all of the above, we said couple of years ago, the Woodside was no longer really a strategic necessity to Shell in terms of executing our LNG strategy in Australia, and we did sell lion part of our shareholding, we still own around 24% of Woodside, and basically the statements still hold. However it’s may not be a strategic asset but it is a valuable asset. It’s…

. : Martijn P. Rats – Morgan Stanley: Yeah, Good afternoon, I have got two if I may, you mentioned that our production from liquids rich shales from U.S. reached 52,000 barrels a day already, which it’s growing at a pretty decent cliff, I was wondering if you could give us a bit of an outlook for how this will progress over the next couple of quarters. What level of growth you still foresee. And secondly I noticed from the cash flow statement that the line dividends received from equity accounted investments, looks light compared to the last quarter and compared to the same quarter last year, and I know there can be joint ventures where sometimes the timing from certain dividends can be, so little specific I was wondering if we are looking at a sort of normalized number or whether we’re actually sort of missing while it could be as much as a $1 billion and also whether this line item given the accounting changes that you highlighted could be affected by that?

Thanks Martijn the liquids rich shales in the U.S. 52,000 barrels oil equivalent per day at the moment, not basically the Permian and the Eagle Ford. We've got some 12 rigs in both, in the two in total, and we're also drilling out other liquids rich opportunities in Canada in particular, so that we're in 20 rigs at the moment on liquids rich activity. We won’t see quite such a step up as we have recently seen because, the 52 is about half of it is in the Permian which was an acquisition in the fourth quarter. But we do expect to see some growth over the rest of the year and just as the benchmark the average onshore shale production was about 260,000 through the totality of 2012, and we are about 320 in Q1 2013, so quite some step up, not helping the turnaround of the Upstream Americas result. I can't give an absolute figure because it does depend on drilling result and overall you may recall we scaled back our absolute activity in the onshore drilling for now just to get the right balance and the right capital discipline into the system. And dividends received on cash flow statement; well spotted, we are somewhat less in terms of receipts than actual earnings in the equity associates. There are several factors here some of the dividend reduction is timing, some of it is step down in share of production sharing contracts reach full cost recovery, and some of it is the accounting change IRFS, that one in particular, doesn’t' come back, and the cash flow is anyway shown elsewhere in the cash flow statement. The last one applied to the Aera joint venture in California, the heavy oil joint venture and that several hundred million dollars that transferred from the dividend line to elsewhere in the statement. So there are three factors there so about half of that difference comes back, the other half doesn't. And hopefully that gives you some feel for where we are on that dividend statement, overall the cash flow progression remains generally positive but there is still some way to go, I am sure you'll have seen relative to the targets that we expect to achieve over the full year period 2012, 2015. Thanks Martijn. Martijn P. Rats – Morgan Stanley: Okay thank you.

Thanks and the next question pleases Daren.

Yes, thanks. The next question comes from Jon Rigby from UBS. Please go ahead with your question. Jon Rigby – UBS Ltd.: Yes hi. A couple of questions, firstly you mentioned on the call that Pearl effectively reach platform on production volumes but can you just talk about over whether it's reached as sort of plateau contribution in terms of earnings and cash flow or is this still more their shake down and start-up costs to work the way out in terms of the contribution to the financials. And secondly just on the Canadian that you referenced small expansion debottlenecking and also talk about Carbon Creek. As you look at your Canadian position, are you able to effectively run all the future potential production from the oil sands through sculpt and therefore sort of avoids some degree, some of the problems that the rest of the industry is having in terms of differentials, although clearly still affect to some degree. Thanks

Thanks Jon, and GTL it’s at plateau or close to plateau production at the moment, but dollar contributions still continues to grow as they especially product market develop for example in lubricants, and clean diesel. There may be a few more dollars we can squeeze out, and overall the big three projects are being quite transparent and opened about, and in the past they've been ramping up, but given they are all pretty much where they need to be now, no need to be very specific other than to say over 440,000 barrel a day of production from the three, which is about where we would expect it to be. We always said about up to 450,000 and we have delivered over $5 billion of cash flow last year from these assets, while obviously at current conditions we should do a little bit better this year. Canada, debottlenecking is relatively smaller. The first one, it’s 6,000 barrel a day Shell share. But remember this is a series of relatively small projects that over time should get to 60,000 Shell share and Common Creek of 80,000 Shell share at the moment. Can we run it all through (inaudible), I’m afraid the answer is no. We would need to move some to Sarnia, some potentially to Puget Sound sand and some to the Gulf Coast. That is the intent or was the intent, clearly will depend on access to appropriate pipeline capacity. And we can only really talk about that at the point at which it’s established particularly Keystone is an important indicator for the industry, although it’s not the only way of moving heavy oil down now to Canada. Jon Rigby – UBS Ltd.: Okay. Just as a numbering test on the detailed plant, is the products like that’s now coming out of it pretty much what you have, or planned or will that develop as you develop the markets? Are you sort of selling the product you planned, but in a slightly distressed pricing or you’re actually moving the products slightly to meet what is currently in the market?

I wouldn’t say we were distressed at all. The market is developing and evolving. It’s very clean, Middle East, and I asked them surprising uses of high value. I can’t say too much more, but it’s developing nicely. And the one thing I would point out is that there is an ethane stream currently, not saying too much value, because you can’t actually take it through the efficient top process and that ethane stream is being allocated in future into the chemical project that we’re now working on with Qatar Petroleum, the Al-Karaana project. So, over time additional investment helps add further value to the hydrocarbon streams in Qatar and also we hope to spot shortly the new exploration well in Block D with partners PetroChina. So Qatar remains an area of potential growth for us, looking good. Jon Rigby – UBS Ltd.: Thank you.

Thanks John.

Thank you. The next question comes from Robert Kessler from Tudor Pickering. Please go ahead with your question. Robert A. Kessler – Tudor Pickering Holt & Co. Securities, Inc.: Your Downstream is also quite strong in the quarter, presumably with the help well as specifically the reference from the trading and marketing. I’m assuming that contribution was towards the higher end of that $800 million to $1.1 billion range. And then, also related to the Downstream, I’m assuming Port Arthur with Motiva still kind of in expansion mode in the quarter. Can you give some sense for the average throughput of that facility for 1Q and how much of an uplift we might expect for the second quarter?

Thanks, Robert. Your assumption is pretty much correct. The marketing and trading, we haven’t given specific figure this quarter, but refining, manufacturing was in a small profit. So the M&T, marketing and trading was indeed at the top end. Just to make the point that trading is not a volatile and open position business. It’s adding the cents per barrel to all the molecules that flow through the system and optimizing the positions we have. So it’s not something that comes and goes. It’s a pretty substantive regular robust contribution to the bottom line. Throughput in Port Arthur, I don’t have a specific number. It’s not 100% from the 320,000 new [branching] project, but it’s close to 300,000. Not a lot of earnings impact in the first quarter as we’re still aiming out some of the product flows, but it’s actually performing pretty well. So it’s about 80%, 90% of its capacity on the distillation unit. So it’s looking good, but not making a big impact on the bottom line just yet. Hopefully that helped. Robert A. Kessler – Tudor Pickering Holt & Co. Securities, Inc.: Yeah. Can I ask for refining overall, I mean, you said chemicals availability will be lower in the second quarter. Can I presume refining availability will be higher particularly with the multi area?

It’s about the same as it was last year and our availability is high, but there’s still actual throughput somewhat below ultimate capacity because of the actual economic opportunities in the market. So it’s not a constraining factor on this at the moment. Okay. Robert A. Kessler – Tudor Pickering Holt & Co. Securities, Inc.: Thank you, Simon.

Operator, can we move on?

Yeah. Thank you. The next question comes from Irene Himona from SG. Please go ahead with your question. Irene Himona – Société Générale South America: Hello, Simon. I had two questions please. Firstly, on gas and the Basrah Gas Company, and can you comment on whether the economics of that project would be conditional on a future LNG export project or whether you can actually deliver the return, an acceptable return selling the gas domestically to power stations? And then secondly on exploration, you’re obviously investing substantial amounts this year, up to $7 billion. What are the highest, most of the existing wells, the highest impact you have this year and importantly, do you intend to update investors and obviously you don’t do it on a well-by-well basis, but would it be on a now talk basis? Thank you.

Thanks, Irene. Yeah, Basrah Gas today, the economics are certainly not condition on future LNG exports. That’s almost the other way around. The LNG economics would need to, I suspect, still require quite some work both on the cost and the value chain piece. So the up front activity is, basically we collect the gas, we strip the liquids, we put dry gas back into power for which there is fee and there is some access to the NGL revenues that we take out and that’s what underpins the returns. So that’s reasonably attractive, better than the oil. Exploration, we’ve got $4 billion going into conventional exploration and $3 billion into unconventional. So unconventional first; the most exciting is some of the LRS, liquids-rich shales in Canada and Argentina. And on the gas side, we are the first well in Ukraine and we have 10 rigs operating in China, not all on exploration, some are in Changbei, and the China and Ukraine on the gas, Argentina and Canada on the liquids. Hopefully I think that the gas from that agreement where we’re looking at opportunities in the Bazhenov shale in Russia, which we would expect to be liquids-rich as well. So that could be of interest whether we’ll get to drill it this year or not, but do not know yet. And on the conventional side, we had hopes to French Guiana. We still have hopes to French Guiana. Unfortunately, the most recent well was not a success. And, but I just mentioned Qatar, which is a gas prospect in the peak of that we will spud shortly. We have two wells in Binene and Gabon Deepwater new plays. We have the Australian well at the moment is (inaudible). We’re interestingly drilling in Albania on land for oil and we…

Thank you. The next question comes from Jason Gammel from Macquarie. Please go ahead with your question. Jason D. Gammel – Macquarie Capital Ltd.: Thanks, Simon. I think I’ll restrict to one because it’s multipart, but it involves the Repsol transaction. I was hoping you could elaborate on the uplift that you could expect to achieve in cash of that business from your trading positions given that a lot of those volumes were essentially point-to-point committed. And then just within that, could you address how having incremental Pacific Basin volumes from Peru will help your trading business in light of a lot of those borrowings already being committed in demands any and I guess really what I’m getting at is would you have other solutions for getting gas in the Mexico that would allow you to re-route the proved LNG to other Pacific Basin markets?

Jason, thank you. You must be doing your homework on the Repsol contract. The uplift that we would expect does depend to an extent on diversion. Let’s me be clear. There’s some fundamental value in those contracts. We are not dependent on non-trading capability for most of the value. Most of the value, it’s just embedded in the contract, so it’s based on today plus the growth potential. And, so the trading is essentially diversions and the ability to meet customer requirements from what is a broad and diverse effective portfolio options within Shell whereas Repsol may not have built an effort to meet customer requirement. The barrels may be point-to-point today, but they are not necessarily hard-wired in the contract. So customer demand can be met from different sources and that’s what we intend to do. That will drive the uplift. I just got to reiterate. First of all, we have to close the deal. It’s something trending out contracts, major contracts, several anti-trust, many partner support required, some project financing in that. So we got a lot of lawyers and a lot of people working hard to close the deal. It’s something 20 odd contracts, major contracts, several anti-trust, many partner, support required, some project financing in that. So we’ve got a lot of lawyers and a lot of people working hard to close that deal and you remember it’s effective October 1, 2012. So we continue to accumulate cash in lock box will be released and credit is against the acquisition costs at the point of closure. Looking good, but still some way to go, don’t expect to see closure in the next quarter, that’s for sure.

Thanks you Jason. Take the question please.

Thank you, the next question comes from Oswald Clint from Sanford Bernstein. Please go ahead with your question. Oswald Clint – Sanford C. Bernstein & Co.: Yes, thank you Simon. I just wanted to ask you again about refining, because I remember you painted a pessimistic picture for refining margin at the end of January and you talked some benefit here in the first quarter, just want to know if you could, are you still seeing that pessimistic view or expect that to take place over 2013 or something exchange to make you a bit more optimistic about refining margins? And then secondly, just looking at your kind of CapEx split here in terms of data book and year-over-year looking at the big delta I think it’s in Europe being the biggest delta despite that being quite a mature part of the business, is there anything in that European CapEx number? I know you’ve added some equity in some North Sea fields, but I don’t think the numbers were disclosed, but is there anything else in terms of European CapEx?

Thanks Oswald. Refining; no real change to the general misery and pessimism on the market, particularly in Europe and actually in the short-term, in Asia. The fundamental issue is, capacity exceeds demand and nobody will close a refinery in Europe. So, we are working our bug out of the system now and we announced potential sale or closure in Australia of Geelong, there the all the new capacity coming on stream, the Middle East and Asia in general more than offset any closures plus demand growth. So, there are good quarters, bad quarters. North America have some interesting opportunities as the whole balance of the refining system is being challenged with over light sweet crude available inland and moving it to large coastal refineries that were built to process heavy power crude has created some short of arbitrage opportunity and it goes towards one itself, you have seen from some of the competitors the shutdowns planned and unplanned because of various incidents that have sort of temporary one of support in the North American markets in particular. I am afraid in April, margins have remained rather week. So, there was a weaker trend during March and that’s continued into April. Our uplift was partly better performance and partly the fact that refinery configuration was reasonably well mapped to the opportunities available, but it’s not a business but that is going to drive the results going forward. The marketing and trading however performed extremely well and in chemicals and what are tough markets. So, we’re particularly pleased with the pretty robust performance there. CapEx split in Europe, Europe is up. Yep, barrels, have an acquisition in there, I think for around $500 million but the big driver over time at the moment is that Clair and Sakhalin project. We also continue to invest in (inaudible) in Ireland but the step up is on the Clair and Sakhalin projects, which are significant and we’re over 50% shareholder in Sakhalin now and 27% in Clair. They will hopefully make nice contributions from 2016, 2017 onwards. They mature as a region, but all those projects, attractive four of them are oil projects, Clair, Sakhalin (inaudible). Oswald Clint – Sanford C. Bernstein & Co.: That’s great Simon, thank you.

Thanks.

Thanks, your next question comes from Iain Reid from Jefferies. Please go ahead with your question. Iain Reid – Jefferies & Company, Inc.: Hi, Simon good morning. Got a couple of question about Asia-Pacific LNG, firstly on Sakhalin; it looks like your partner there is interested in building Southern LNG facility, (inaudible) talking about a facility in the region is this is effectively the mainly the expansion at Sakhalin, your Sakhalin plant is kind of off the table for the moment? And secondly on Papua New Guinea, I think you mentioned last year that you were looking at InterOil acreage there. Can you tell about data on what the plans are there, I believe we have been running a process for selecting partners, we would like to hear something from there?

Thanks Iain. In Asia-Pacific LNG, well Russia specifically they mentioned hopefully you all picked up I guess from Neft announcement on buying some of Shell Arctic opportunities together with Gazprom Neft, signed in the presence of the President and also Alexey Miller, the Chief Executive and Chairman of Gazprom. The Train 3 option at Sakhalin continues to be worth. We have work ongoing in terms of the design and it is one of the options available to Russia Inc. and Gazprom in particular to expand and enhance the LNG market presence. (inaudible) of course, but it is both the cheapest and by far the quickest way of achieving that, but they will assume decisions ahead of us. So progress continues and there is competition within the Russian system, but on the straight economics and speed to market in an important window of opportunity as well and particularly when you look at the direct competition potentially coming out of the North American continent and if Russia wishes to capture a market window before that arrives and then tackle in and it’s certainly workable option we believe. At PNG, the recap of what I quoted as context a year ago, so that is InterOil process. Clearly, we have taken a look from a distance and I can’t really comment any further, other than to say, I think I started on the Australian project portfolio and LNG. We are known to be working the floating LNG project. We have partners impact. We are also the operators of course in Indonesia. We are working in Canada LNG very actively at the moment and we announced the Elba Island export facility plus of course the volumes. The whole LNG business is progressing at quite a rate at the moment for us and any new opportunities will have to look pretty attractive to displace the ones that I have just talked about. That’s all I can say really. Iain Reid – Jefferies & Company, Inc.: You can’t comment on why they are still part of the InterOil process?

No. Iain Reid – Jefferies & Company, Inc.: All right. Fair enough. Thanks very much.

Convey my regards to Peter, please. Iain Reid – Jefferies & Company, Inc.: I will do. Thank you very much and much appreciated.

Next question please.

Thank you. The next question comes from (inaudible)

Thanks. If I could, just ask around on the cost side. The first thing today and lots of volatility in quarter-to-quarter basis, so I am just wondering what you are seeing underlying on the cost side? And then secondly, if I could on the U.S. data transfer section, how effectively you essentially see that and it being? Thank you.

Thanks. Good questions. The cost base is one impacted the proportional consolidation the IFRS 11, but maybe not quite volatile as you might think. The underlying trends are in the downstream we are generally reducing, its par driven by divestment and par driven from just squeezing cents on the dollar everyday and everything that we do, that’s underpinning some of the robustness of the result that we see. The upstream, international costs holding roughly flat, it’s an upward pressure from new projects coming on stream and the Americas they are going up as we execute more activity as more exploration expenses in the quarter. It’s one of the challenges in the Americas is to ensure that the cost grows more slowly than the revenue and that’s ongoing work with the management team there. We are seeing fee exit at relatively high level. Our feasibility expenditure on new project is potential, but generally the costs over the past few years have been held at $42 billion, $43 billion total over about four years now. So the cost not a major issue in terms of results progression. Next to transport; good question. When we started, we may have had said aspirations for this market. What we are essentially doing is, producing LNG in small scale and selling it to trucks, fleet operators and to shipping small fleet operators and shipping or large enough to justify the investment anyway. That market we saw may take some to develop because we need original equipment manufacturers for both engines and vehicles or the ship and then we needed a distribution network and most importantly what we need is customers. We have been surprised that how quickly this is coming together. We have many manufacturers now looking at this and commenced at west port in North America, but just in China alone I think at Guangdong 17,000 trucks and buses running now on LNG; that’s growing faster. Chinese manufacturers were seeing appetite for LNG barges running down the Rhine in Europe. We acquired Gasnor, which LNG for shipping provider in Norway last year. So potential is multimillion ton per annum. Much of this will not necessarily be provided from our own upstream gas production. It will depend basically on the logistics close buyback. We see the take up of the various parts of the value chain accelerating in an attractive way and our challenge and opportunity is to ensure that we confine an offer for the customers, right pricing, the right distribution that helps us develop leading position there. So it could be very substantial globally over a period of time and we see North America and China in particular is growing this as a major part of the transport fuel mix.

That’s very helpful. Thank you.

Thanks, [Letty]

Thank you. The next question comes from Peter Hutton from RBC. Please go ahead with your question. Peter Hutton – RBC Capital Markets: Good afternoon Simon, just two quick questions. The Q1 marked a welcome return to profit in the Americas, but just Q1 last year, the profitability there was much higher than it was for the rest of the year, were there any seasonal factors in Q1 on costs; really such as BP mentioned, which also impact Shell there? And secondly, just coming back to your helpful discussion on shareholder buyback, under what circumstances do you think this could become an option in your financial framework? I mean you mentioned, no borrowing to do this, but a lot of your peers see this as effective way, flexibility to return a surplus cash through to shareholders. I mean –if you just see specific issues on the mechanics of Shell; of shareholder buybacks or is there a view that the rates of return on your own internal projects, still most expect than buying your shares at present levels?

Thanks, Peter. Couple of good hooks there, the Americas profit is down year-on-year, probably that’s in by higher exploration expenses, sorry feasibility expenses, plus some of the issues that we’ve acquired a lot. And the Permian acquisition from Chesapeake was most obvious, but quite a few other smaller players we’re buying. And as we bring in and integrate; that activity introduce sort of different standards around things like safety. Did you see some of the costs go up before they go down. So that is year-on-year, all of those things are some thing as a factor. You referred to, I think over Mexico costs. In practice, we don’t see those going up at all really in project, and in fact we’re seeing very good progress on Mars-B, Cardamom and the BC-10 Brazilian project are very progressed towards production next year. Those contract scores were put in place back in 2010, mostly; While the market was lower, and we’re doing okay there. We’re currently progressing stones towards FID, and which should be a floater, floating production storage unit; has a 3 billion barrel resource number as well in the lower tertiary side. It will be one of the major developments up from, because it will be more in early production system. But that will be the next one, and costs that’s not that much of an issue in the Gulf yet. It could be if other projects will take off of course. And just back on the shale, costs actually on the drilling and the activity not too much inflation there at the moment, it’s more on the administration, and if you manage across the 14 basins that we’re in at the moment, and you may recall actually we’ve spent $28 billion on the balance sheet three month ago. So we’re…

Thank you. The next question comes from Alejandro Demichelis from Exane. Please go ahead with your question. Alejandro A. Demichelis – Exane Ltd.: Yes. Good afternoon, Simon. Just one clarification and follow-up from the previous question. In terms of the buyback, you mentioned in the $4 billion to $5 billion for this year, and clearly that you’re not prepared to increase debt to meet this. Should we assume that if for whatever reasons or guess what you drop in the second half of the year, that $4 billion to $5 billion may not be there?

And that’s a fair question. I’m looking more at what we’ve already delivered from free cash flow than what we’re about to deliver from free cash flow. The oil price dropped to 70, we may look at the buyback program, but for now we don’t see a problem with that. Alejandro A. Demichelis – Exane Ltd.: Great. Thank you.

Thanks. Our next question comes from Kim Fustier from Credit Suisse. Please go ahead with your question? Kim Fustier – Credit Suisse: Yeah. Hi Simon, just two questions, please? Firstly on Alaska, I was hoping you could give us some color on the drilling program there, which was postponed I guess two months ago. Basically, what are the next steps, and any color as well on the accounting treatment of the costs of this year? Secondly on Nigeria, I was hoping you could provide some updates there on how much of the 30,000 barrels a day lost in Q1 do you expect to see coming back in the next few quarters, in other words how much of this as a sabotage is endemic? Thank you.

Thanks, Kim. On Alaska program, we did the two top holes, and we will not drill this year. We have both rigs are in the yards at the moment in Asia. One is for repair, one is for potential upgrade. We will not take a decision on when and how we drill in 2014, until we’ve been through some of the work with the repair yards, but also it’s very important, I think we get all the reduction in the row this year, and that we are not left with a critical path depending on any one piece of equipment as we were last year, which essentially was permitting, they’re in the containment barge. That containment barge just for your information is now fully permitted and ready to roll. So it’s really the rigs, and the permitting system, so we want to see both of those progress to the reasonable level of confidence this year, we don’t leave it to April, May next year before we can say more. We run now for a month or two really. I can’t give a date as to the engineering work that needs to be done. The accounting treatment is, pretty much as I said, still at the last quarter results, we have, now it’s back $2.8 billion on the balance sheet, just under $1.8 of that is the remaining signature bonus that we are amortizing slowly overtime; according to the probability of success, which has not changed. We still expect to drill less or the probability of overall success, we have not changed. If we found we were not likely to drill, and that may have an accounting impact, but for now that has not changed. The same is essentially true, the remaining balance which related $500 million, $700 million to the…

Next question please, operator?

Thank you. The next question comes from Fred Lucas from JPMorgan. Please go ahead with your question? Fred Lucas – JPMorgan Securities Plc: Thank you, operator. Simon, there’s another big diesel machine ramping up in the Middle East, it’s Aramco’s [Jeddah] refinery, 400,000 a day, of which more than half the product slate is diesel, what impact do you think that will have on the profitability of held GTL over the coming months? Second question is, you mentioned that you do have a focus on free cash flow growth, that’s a target for the business, and that’s certainly our focus for the market. Why don’t you move your operating cash flow target to free cash flow target to help them mark even further, and to gulf the net lower rising the risk of rising CapEx, and if I could squeeze a third one in, and it’s just is a numerical answer. Can you put a number to how much of you oil sands output doesn’t make into scope for upgrade; so for every 10 barrels to say how much doesn’t?

Okay. Thanks, Fred, I’ll see if I can do justice. The first one is relatively easy. Big diesel machine GTL profitability is underpinned by base oil and special products, and being purely clean diesel. So unless to say these can produce completely clean and sulfur-free diesel from crude oil, they will not be impacting the markets where we have seen premium pricing. Free cash flow target growth. Good question about the way we think of it, and CFFO cash flow from operations is a target for the people who operate our assets, which is most people who work with Shell. Free cash flow is the difference between that and what we choose to invest or divest, those choices are made by a very small number of people in Shell and are a completely different decision process. Our focus on CFFO growth is to deliver maximum cash flow from the assets and the businesses that we currently operate today. It’s what we focus our people on, it’s what we deliver. If you deliver that, it gives us the choices to make on both rewarding shareholders and reinvesting. We know roughly what we need to reinvest to be able to sustain that growth and that figure can change over time as you need even more growth or individual project change, but for now we know what that figure is. If we set a free cash flow target either for the company or for your or for our own people sorry, we would just encourage people to sell stuff. It’s just simple as that or to invest less in the wrong thing. So, it’s a question of who gets to choose, all those big decisions. And fundamentally most of the organization is focused on safely and reliably producing, selling products to customers. And we will reserve the big decisions on portfolio investment, savings and capital allocation for relatively few people. Fred Lucas – JPMorgan Securities Plc: You say you know the level of investment that you need to get your growth target. Could you share that number with us?

It’s 33 this year and it’s net 130 over the figures 2012 to 2015. Fred Lucas – JPMorgan Securities Plc: But out to 2017 and 2018 to get to the 4 million a day?

Well, the 4 million a day, those are clue in what I said earlier that we will invest in at least four projects now all the volume associated with them at all, but will lead to equivalent cash flow growth. Then the investment is going to reduce post 2015, but I certainly have no mandate to confirm that all together an alternative figure. So the 130 billion if you remember the arithmetic based on what we already sell, already invested, already acquired and sold. It doesn't actually allow for Repsol, I will say. But all other things being equal, we would expect mid-30’s growth CapEx for the next couple of years. So slightly higher than we are at this year and the numbers go round and lead to delivery of equivalent financial growth in 2017, 2018. And again, to give you any growth or cash flow I want to merely by drilling shale out in North America. We’re only going to do that when it make sense to make competitive returns. So I need to manage that red line on the graph, but when 87,000 people thinking they’re managing it, is basically the message. Last point, oil sands production to Scott Ford, the upgrade basically will process everything into the mines. Some of the debottlenecking we’re doing at the moment will increase the upgrading capacity. We’re not able to - the upgraders because only produce syn crude, they don’t produce a lot of finished product because we brought that into the Scott Ford refinery and the refinery is smaller than the upgraders. So we are actually moving upgraded crude for example, Sarnia and the West Coast some of this coming by rail to the West Coast and ultimately to be the most likely some sympathy crude, but also some just basically diluted bitumen that will go to the Gulf Coast. But at the moment everything can be upgraded, 10,000 barrel a day coming out of Peace River, which you know of the quality that can go through the upgrader. And in future we will not, it's highly unlikely we will build new upgraders if and when we grow the heavy oil production further. Our aim will be to take it into our own refining network. Fred Lucas – JPMorgan Securities Plc: Okay, fine.

Hopefully that covers. Fred Lucas – JPMorgan Securities Plc: Yeah. Thanks.

The next question comes from Guy Baber from Simmons & Co. Please go ahead with your questions. Guy A. Baber – Simmons & Co. International: Thanks for taking my question. I was just hoping you could address the environment for asset divestitures right now, but your guidance this year is I believe just 3 billion which should be the lowest total on a couple of years for you all and last year we ended up doing little bit more than twice what the original guidance was. So just wondering why the lower expectation this year. Is it reflective of broader market conditions or is it more specifically that you are just more comfortable with your existing portfolio right now? And then I have follow-up too.

Okay. I’ll try and do justice. We start every year, $2 billion to $3 billion. That’s what we would expect the business always to be looking to upgrade off the bottom end. Previously we had slightly higher targets because we had a major downstream program in progress for about five years. That major program is now basically running out and we talked about it lately in the refinery in Australia et cetera but these are not major factors. So we’d expect $2 billion to $3 billion. The reason we often do more is that sometimes opportunity knock literally. It took us three weeks to define and close the whole divestment for $600 million last year. And we, at that point in time, we don’t actually see major transactions that would take us above the $3 billion in the calendar year of 2013. That does not mean we are not looking potential for 2014 and beyond and back to the earlier question on free cash flow that is one of our major levers, but we don’t have a higher target. We may deliver more depending on opportunity. I hope that gives you some feel for how we see this. Guy A. Baber – Simmons & Co. International: Yeah.

Do you another question? Guy A. Baber – Simmons & Co. International: Yeah. My follow-up was on U.S. gas production. That production very strong this quarter presumably on some Marcellus ramp, but hoping you could provide for us the framework for how you plan to manage productions in the balance of the year and activity level in line of some of the major variables. So Marcellus, some of the improvement we’ve seen in spot gas pricing, but also just considering how materially you’ve cut the capital budget there for gas this year.

Okay. Most of the current gas activities actually in West Canada are in the Groundbirch more than Marcellus, twice as many rigs there. And we’re also producing some gas in the Eagle Ford along with the liquid. So that’s how some stronger gas production. In practice, going forward we’ve taken about 25% of the rigs out in North America from this time last year and that’s part because we reallocated the high level CapEx to other parts of the portfolio. Price is now $4.30, I think, in gas terms. Even that price is probably still more attractive to keep the rigs very much on the liquids rig shale appraisal activity as much as production as well and to ensure that we are drilling, for example, the China, Ukraine exploration opportunities. So we’re not actually planning already then to ramp back up again in a material way in North America in gas at this point in the market. Guy A. Baber – Simmons & Co. International : Okay. Thanks for the comment.

Thanks. The next question please?

Thank you. The next question comes from Hootan Yazhari from Bank of America Merrill Lynch. Please go ahead with your question. Hootan Yazhari – Bank of America Merrill Lynch : Thank you, Simon, two questions please. Starting with a very simple one. How should we be thinking about the CapEx figure for this year all in with all the different portfolio activities you’ve conducted both from a growth and net level? And then going forward, just to get a clear idea of how you’re thinking about project planning et cetera, how are you looking at projects to add value to Downstream in the United States versus your growth targets for 2017, 2018? I mean, is there a case to start to push up some of the potential LNG, GTO, GTT et cetera projects up the chain and thereby displace some of the growth there or do you feel that or would you be more willing to relever the balance sheet up and include everything? Thank you.

Thanks Hootan. CapEx for this year is a fairly good question. Actually the Board is asking rather at the moment and other than $34 billion plus $2 billion, which is the official statement plus Repsol I’ve no real change to make. The $34 billion organic plus $2 billion acquisition, which is completing last year barrels we have in Iraq and less $3 billion divestment, net $33 billion add back Repsol, which is effectively full point for cashless whatever we have in the lock box when we open it. And Repsol might be next year in practice as happens. So and with lot of the things I’ve talked about in portfolio terms were already allowed for in what I’ve just stated and won’t really impact CapEx until future years. We’ll update as we go through the year with more detail. Obviously, as I answered the previous question on free cash flow portfolio activities will be discussed and agreed from Board level down with the free cash flow objective in mind. And projects Downstream in the U.S. actually there are quite a few opportunities, everything ranging from buying railcars to LPG exports to tweaking the refineries to protest the crudes that are available, all being thought about in progress not just by others well of course at the moment. In absolute materiality terms not yet that significant will help to grow CFFO or protect current CFFO. So very much part of the thinking as is the same thinking around gas, where will the gas get moved within the continent. The big projects to monetize, well, we already talked about Elba and the gas to transport project. These are what I call the medium sized projects and committed on those export LNG. Big projects Canada LNG is pretty much highest priority that we do need to get move in because of the good partners we have there. Again that Gas-to-Liquids, Gas-to-Chemicals very much in the mix in terms of optionality unlikely to see a whole lot of CapEx in that period up to 2015. Could we accelerate would be a challenge for engineering reasons more than anything else and that they are more of the projects we will invest in the second half of the decade that will deliver the growth out beyond the 2017, 2018 period rather than for the 2017, 2018 period. Hopefully that gives you feel for the phasing. Hootan Yazhari – Bank of America Merrill Lynch : Yeah, that was very clear. Thank you, Simon.

Thanks. Next question please?

Thank you. The next question comes from Jason Kenney from Santander. Please go ahead with your question. Jason S. Kenney – Banco Santander South America: Hi, Simon. Thanks for taking the call. It’s been quite a long question-and-answer session for you, I understand. I’ve got a query on the tax charge, underlying tax charge, which I think was around 38% in the quarter versus perhaps a more normal 45%. I did notice that there was the tax credits in result it was a $730 million, which compares to the whole year 2012 $629 million. So can you just give me some detail around tax and that tax credit in particular? And then, maybe secondly, on the gearing at 9.1%, have you got a view of where gearing might exit 2013, if Brent oil price stayed at $100?

Thanks Jason. Tax charge, two things really, structurally the more the downstream mix in proportion of the total will lower the effective tax rate and, but there are some more that I mentioned in the indentified items in Australia and there was one court judgment went in our favor in Europe. So we’ve $600 million of tax credit and indentified items. The actual underlying clean effective tax rate was 42%, which compares with about 44% a year ago. So it is going down, but that shift is mainly the downstream being more high percentage of the earnings. 9% gearing, a good place to be if we execute all of the buybacks and if we just stick to the net CapEx I’ve just talked about plus paying for Repsol and it’s not going to go down further I don’t think. Having said that, there are quite a few things that could change between now and then. Our range is 0% to 30%. My aim is to keep the lower half of that because our rating agency friends look at everything that’s not on the balance sheet also and which actually make the effective gearing a bit higher than 9%. And thanks Jason. Jason S. Kenney – Banco Santander South America: Thanks.

Next question?

Thank you. The next question comes from Lucas Herrmann from Deutsche Bank. Please go ahead with your question. Lucas O. Herrmann – Deutsche Bank : Thanks very much. Simon, afternoon. Two, if I can. First, just chemicals, if you could talk a little bit more about the performance. Doesn’t seem the environment has changed dramatically, but the profit performance certainly appears to have. And secondly, a broader question, are you happy with the way that cash flow is developing vis-à-vis your forecast and the question simply that the guidance broadly was $100 over the four year period $200 billion or so of operating cash flow, about $46 million last year. You are annualizing at $110 million this year, somewhere near $44 million. So it condensates $110 million is what you need in 2014, 2015. So are you happy with how things are developing and are we really looking for this. Are you ready to take another step change in Gulf of Mexico barrels come on in 2015 and Gorgon comes on in 2015 and those businesses start to make a material difference to the cash delivered?

Okay, thanks Lucas. Good afternoon. Chemicals performance is generally pretty solid around the world. Even in Europe, we have base chemicals performance improving and staying reasonable demand and margins. And Asia-Pacific it was good place to be in, some of the more specialist products, the intermediate products, mono ethyl glycol, MEG and ethylene oxides. So just generally well positioned business and benefits compared to say four, five years ago fundamentally from the switch to ethane field in the United States, so, quite a robust performance, great outcome from (inaudible) in charge. The general CFFO developing, am I happy? Lucas, I am a CFO, I am paid not to be happy. So it clearly there are quite a few issues area that I think we can improve on, but strategically and structurally the big projects are either up and running or they are in place. The growth you are absolutely right, needs to continue from now till the end of 2015 to meet those real expectations up to $175 billion to $200 billion over the full year. So as to put it simply, you have to get to $50 billion via cash flow and then push on from that towards $55 billion and beyond. So to get to $50 billion, there is improvement underlying improvement whether it’s cost and the unit margins we generate, the improved customer profitability, lots still to come, downstream and to be honest upstream and adjusting things better in the business. It is not big project, it is the 87,000 people, doing the right thing everyday and doing it a bit better tomorrow. : Now, Majnoon and Kashagan will make little difference this year, hopefully seasoned performance next year. You mentioned that deepwater projects, Yes, Mars-B, Cardamom and BC-10 together with in 2015, definitely we’d like to see Gorgon producing. Those big projects will certainly make a difference. We are talking multiple billion or plus that. But fundamentally the challenge today, 12 months is primarily steady progress, downstream and upstream, taking the extra dollars and the flow of the hydrocarbons that we’re involved in. We’ve always said these are ambitious target, and whatever way you do the arithmetic we are bit behind the curve and some of that we can look at the macro, so of those things we ourselves work on. I will only say that if you look in the competitive performance we are currently behind the curve against our own aspirations, we seem to be ahead of everybody else. And I will support that Lucas. Lucas O. Herrmann – Deutsche Bank: Simon, I will let you stop there. Listen, thank you.

Thank you. Let me move on. Next question please.

Thank you the next question comes from Stephen Simko from Morningstar Equity Research. Please go ahead with your question. Stephen Simko – Morningstar Equity Research: Hi, how are you doing?

Hi, Stephen. Stephen Simko – Morningstar Equity Research: Simon, I just wanted to ask you, I believe it was last quarter, you kind of gave a sort of multi-quarter view of upstream Americas, again sort of helping the progress in terms of production coming on line from the Gorgon shale and the profitability coming from your Gulf of Mexico project that will be coming staring to come online next year. And I just wondered if you could again for investors looking at just how profits are going to trend up from here. Simon, can you hear me, okay.

Yeah, I can hear you, there is little bit of background noise, but Americas I shy away from production forecast, but we are established now 320,000 of production a day onshore. We are about 190,000 in the Gulf in the deepwater offshore, that 190,000 was a bit below trend, some plant maintenance, some downtime in the Gorgon platform. We are ramping up still production in Great White, (inaudible). So there are still production to return in the Gulf that is production to grow although not as quickly as we have done over the past three to four months, over the rest of this year. The oil sands was producing, yeah pretty much a potential in the first quarter, it was a good quarter performance. So as the production growth should be steady and the income should come with it this year, the major projects next year, that’s Mars-B and Cardamom in particular. And when we report Upstream Americas we include Brazil, so the BC-10 and (inaudible) both have additional production coming on next year. So next year is the where you see some of the step up is more a steady growth this year as we effectively the availability in the onshore. I hope, and as well as the perspectives. I think it’s just time to move to the last question please and if there as well.

Thank you. That was the last question. Please continue with any points you’d like to rope.

Okay. That’s the last question. Thank you. And it’s been quite a (inaudible), so thank you for your questions. Thank you for your interest. And the second quarter results will be released on the first of August, and I hope that’s not too late for you and your holiday plans, and I look forward to talking to you again then. Thank you very much for listening. Take care.

Thank you. That concludes today’s conference. Thank you for participating. You may now disconnect.