Shell plc (SHEL) Q1 2011 Earnings Report, Transcript and Summary

Thank you. Good afternoon and welcome to Royal Dutch Shell’s First Quarter 2011 Results Presentation. First the disclaimer statement. I’ll now take you through the results and leave plenty of time for your questions. Our CCS earnings, current cost of supplies excluding identified items were $6.3 billion in the first quarter, that was an earnings per share increase of 29% compared with the first quarter 2010. Our earnings have increased from year-ago levels, in both Upstream and the Downstream. The results in the quarter really are a snapshot of our delivery on strategy. Our focus on improving near-term performance and non-delivering profitable growth in the medium and longer term. We have announced new asset sales and cost savings programmes, all part of the focus on continuous improvement and helps enhance profitability and performance. We’ve sold $3.2 billion of non-core assets in the quarter, further disposals in hand. We are delivering the growth projects that we have launched over the past few year's, this joins the growth to 2012 and it's clear we are working on new options for the next wave of investment, for the growth to 2014 and beyond. During the quarter we started production at two new projects the Schoonebeek, heavy oil project in the Netherlands and Qatargas 4 LNG project in Qatar, which together would add 90,000 barrels of oil equivalent per day for Shell when they're both at their peak production. And we continue to crystallize new investment options for the medium-term, and with exploration success, and entry into the Chevron-operated Wheatstone LNG project in Australia. For the next wave of growth to 2020 we have over 30 new projects on the drawing board at the moment which will generate new options for growth in that period. So, we are making good progress against our targets, to deliver a more competitive performance from Shell. So, let me move to few more details on the results starting with the macro. If you look at the overall macro picture compared to the first quarter a year ago oil prices and our gas realisation increased. However, the spread between oil and natural gas realisations remains relatively wide and North American gas prices actually declined. Chemicals margins increased in most regions against the first quarter last year, although with lower industry margins in Asia. And we have a mixed refining environment industry margins declined in Europe and the U.S. Gulf Coast, and increased in Asia and the U.S. West Coast. However, our own refinery configuration delivered increased margins in the U.S., broadly similar margins in Europe, and a decline in Asia. We have updated the industry refining margin trackers let me show you here for the U.S. Gulf Coast and for Europe in the results announcements that we made today. These changes reflect the declining availability of pure Brent crude, and market discrepancies in WTS, West Texas South, prices. And we switched to margins based on Dated Brent, which is a blend of North Sea crudes, rather than that pure Brent price for the European refining margins, and we switched to Mars coking margins for the Gulf Coast, rather than WTS. Turning now to our earnings. The headline CCS earnings of $6.9 billion for the quarter included identified items of $0.6 billion. CCS earnings, excluding identified items were $6.3 billion the clean earnings, and the underlying EPS increased by 29%. The cash flow from operations we generated in the quarter was $8.6 billion or $13.1 billion if we exclude working capital movements. Our dividend for the quarter is US$0.42 per share, as we have previously indicated. We are offering a scrip dividend programme for the first quarter of 2011, where eligible shareholders can take the dividend as new shares, and all of the information for that of course is on our website. Our quarter saw higher earnings in both Upstream and Downstream, so let me talk about the business performance in a bit more detail. Firstly the upstream. Excluding identified items, the upstream earnings increased by 8% to $4.6 billion in the first quarter and that compares with the first quarter of last year. The main drivers in these results were higher oil and gas prices, and higher dividends from an LNG joint venture. These positives were partly offset by increases in costs related to the start-up of new projects, increased feasibility study costs, and higher taxes. Earnings were also impacted by weaker natural gas trading results, divestments and maintenance downtime. Upstream production, at 3.5 million barrels of oil equivalent per day, and that declined year-on-year by a headline 3%. We saw reduced demand for gas in the quarter some 50,000 barrels of oil equivalent per day we had 90,000 barrels of oil equivalent per day of maintenance downtime impacts and the divestment had an impact of 85,000 barrels of oil equivalent per day. However, the underlying performance was better and volumes were flat on year-ago levels excluding only the impact of the asset sales. LNG volumes increased by 4% to 4.4 million tonnes, reflecting higher volumes from Nigeria and the startup in Qatar and production overall from new fields and field ramp-ups was around 230,000 barrels of oil equivalent per day, higher than it was a year ago and that more than offset the underlying field declines around 160,000 barrels a day. All reflecting the medium-term plan for production and cash flow growth, where the key target are of course next year 2012. As you know or will know the UK government announced during the quarter a tax increase for Upstream. There is a negative impact of some $60 million from this in our first quarter results on a clean basis. To give you an idea of the forward impact at current oil prices, we are expecting a further $150 million charge for the rest of 2011, and then an increase to around $100 million per quarter for 2012. In addition to these charges, we are expecting to take a one off $500 million charge for the tax change relating to the deferred tax provision on abandonment cost once the legislation is actually enacted, and we think that most likely in first quarter of 2012. Turning now to the Downstream. Excluding identified items, the Downstream CCS earnings increased substantially from the first quarter last year to some $1.7 billion. Refining made a small profit compared to the year-ago losses. In fact, it was the first profit for a couple of years. Refining earnings also improved from the fourth quarter 2010, where we had impacts we advised from downtime at the catalytic crackers at Port Arthur in the U.S. and Pernis in the Netherlands, and proceed came back on line during the first quarter. And for the second quarter we do expect refinery availability to be lower than it actually was in the first quarter and that’s due to planned turnaround activity in both Europe and North America and that’s just normal turnaround. The first quarter marketing earnings increased from year-ago levels, it was driven by higher trading and lubricants results, these were offset partly by lower retail figures, where of course, higher oil prices due tend to reduce margins as the price goes up. Chemicals earnings increased from year-ago levels, underpinned by higher margins and volumes. However, we did start to see the impact of weaker industry margins in Asia, and maintenance downtime at our own Bukom chemicals facility in Singapore, and that maintenance downtime will continue for most of the second quarter. So, those are the earnings. Now, turning to the cash flow. Cash generation on a 12 month rolling basis was $46 billion, that includes $10 billion of disposals proceeds, and over that period the Brent oil price have reached to $87. This, combined to the on-going capital spending programme, this resulted in a slight reduction in balance sheet gearing in the quarter, to 14%, and that compares with the 17% we saw at the end of 2010. And also fits very well in the zero to 30% range that we look at for the company in the overall financial framework. I should update you that we expect to complete the Raizen joint venture. That’s the sugar-ethanol downstream marketing joint venture in Brazil. Expect to complete sometime in the second quarter of 2011, when we do that we will recognize $1.6 billion as capital investment. You will also see that then flow through as cash out around $600 million on completion, not the first of three payment over the next couple of years. So, we don’t see all the cash flow immediately. We continue to watch the cash position and the balance sheet very carefully, and I’m pleased to see this quarter the inflow and the outflow rebalancing to a surplus, albeit assisted a growth by higher oil prices and asset sales. Let me just recap on asset sales, which are an important part of the continuous improvement programme they help improve our capital efficiency and more importantly refocus the portfolio on profitable growth. Asset, the sales proceeds for the quarter were $3.2 billion. Upstream, we have concluded $2.4 billion of this, and that covered 60,000 barrels of oil equivalent per day of production, with the prime transaction being the exit from our South Texas tight gas production. In the Downstream we concluded $800 million of non-core marketing positions divestment. As to overall a very good start against the plan for this year to divest up to $5 billion of asset. In addition during the first quarter we announced further potential asset sales, which should complete later in 2011 and 2012. Now these included, in the Downstream, selling the Stanlow refinery in the UK, and reducing our marketing exposure in Chile and in several African countries. We have also begun at the end of the quarter staff consultation to convert the Clyde refinery in Sydney, Australia to an import terminal. And always further improve on refocusing the Downstream portfolio for higher profitability and selective growth and you all you know we are still working on the $1 billion of cost reduction for 2011, 2012 that we have targeted from the Downstream. Turning now to the growth. We started two new projects in the quarter part of a sequence of over 20 new projects in the full-year 2011, 2014 timeframe. In the Netherlands, we restarted production at the 20,000 barrel a day Schoonebeek heavy oil project. Schoonebeek is actually a rather old field, that has already produced 250 million barrels since 1947 when it first came on stream. With the field was shut in for economic reasons in 1996, but we looked at it again to find ways to extract more oil from this. With our value-added technology, this new steam flood scheme is expected to produce a further 120 million barrels over the next 25 years. And that’s a bid almost 50% uplift on recovery. In Qatar, I’m delighted to confirm we had a successful start-up so far at the 7.8 million tonnes per year Qatargas 4 LNG project. Our train is now running at full capacity and has been from the beginning of April. It delivered its first LNG cargo only on 19th of February to Hazira in India, so very quick ramp up. Later this year Qatargas will start deliveries to Dubai and China in line with the long-term contracts. Staying in Qatar, and I’m sure you will have an interest in this. We also achieved first gas from the offshore into the Pearl GTL project. This is an important milestone for Pearl, ahead of GTL Train 1 start up sometime in the middle of this year. We have actually now started to make syngas in the first bank of reactors at Pearl in the 1st Train, this is our Shell proprietary technology, the next step is to take out syngas into the GTL reactors to make the wax. After that we take the wax into, you may recall, the refinery combustion units at the end of the Train before we produce that first product sometime in the middle of this year. We have also an update on Canada growth. In the oil sands, we are making good progress starting up the expansion project. The mine production is gradually increasing and we are actually using some spare capacity in the original Scotford upgrader to process this bitumen. The construction of the upgrader the expansion was completed in the first quarter. We are now in early commissioning stages and we should be fully operational by the end of the second quarter as planned. So, overall, particularly on those big three projects, good progress bringing them on stream, on track, growing the company towards 2012. Looking at it a little bit longer beyond 2012, we also have made progress crystallising some of the longer-term options. Just to remind you, we are planning to take final investment decision on some 10 new projects in 2011, 2012, these include Prelude Floating LNG in Australia debottlenecking the Athabasca oil sands project, and deep water oil & gas developments at the Cardamon discovery in the Gulf of Mexico. In Australia, we have just included our share in recent gas discoveries in the Carnarvon Basin, we have included that into the Chevron-operated Wheatstone LNG project. So, now in that project we have an 8% stake in the unitized gas fields for Upstream production, and 6.4% stake in the liquefaction facilities to produce LNG. Wheatstone is being designed as a two train, 8.9 million tonnes per year LNG project. On the exploration side, we also confirmed during the quarter the significant Geronggong discovery in deepwater Brunei and it was actually drilled last year and after the quarter resource potential of some 200 million barrels. So, just to summarize. Excluding identified items, the CCS earnings per share increased by some 29% year-on-year and performed during the quarter we believed underlines that we are delivering on our strategy. We are making good progress on our three strategic themes that’s the shorter term performance focus, the medium term growth delivery to 2012, and creating new growth options into the rest of the decade. Our priorities remain a sharper delivery of strategy, aiming for profitable growth and a more competitive overall performance. And with that let’s move to take your questions. Ask please could you try and restrict yourselves to just one or two (inaudible), we have the opportunity for everybody to ask a question. Operator, please can I ask you to poll for questions. Thank you.

(Operator Instructions) The first question comes from Oswald Clint from Sanford Bernstein. Please go ahead sir.

Good afternoon. Maybe just a question on Asian gas, and I'm just wondering with the strong Asian gas demand and the Japanese events of the quarter, how you're thinking about demand in that region, and is there any thoughts around Sakhalin 2 in terms of it being expanded? Is that something that could be done? Is it something you're thinking about and would you have sufficient gas in the region to think about a third train there? And the second question just on your European gas production in the quarter was down quite significantly. You mentioned some reduced demand there. Could you just say if that was actual production declines or was that a pure demand phenomenon? Thank you.

I think some of your research covering this subject Asian gas, so thanks for the question. The Asian gas demand short-term yet has been painted by the Japanese situation. We have diverted 11 cargoes swap that diverted into Japan to try and help with the parent situation there, and we are basically putting in a normal contract price. It has an impact but essentially it's not making a big impact on earnings. We think they could be taking up to a million tones a month for sometime, which actually adds up to more than Sakhalin’s production if were to continue in that level for a year. And medium and longer term we have always seen Asian gas demand as a prime driver of that strategy. And about a third of the demand global gas demand growth in total comes from China and close to another third from Asia and all Middle Eastern markets. So, two-thirds overall and we don’t see any reduction in that if anything is potentially an increase. What we have certainly been able to do over the past 3 to 6 months is take all spare gas because Qatar is producing earlier and faster than we had expected or we have spare gas but Qatar has been open market now away from North America and into the higher value market in Asia and the Europe. And the question about Sakhalin 2, the expansion is obviously technically and operationally possible. We have in November time an MOU, Peter was with Gazprom in November, where we agreed to look at opportunities to expand their activities in Russia and potentially to with the flip side thing cooperation in project outside the Russia with Gazprom. We continue to look at that opportunity with Gazprom, it would almost certainly require as accessing more gas in the Sakhalin 3 area which is under Gazprom control. But we know the growth as to report on that . So, yes, we would be interested, no we don’t have concrete milestones on that. Our main growth in gas production to supply the Asian market will come from Australia the multiple projects that we have there. On the European gas production, I mentioned 50,000 barrels of oil equivalent per day reduction that make 300 million of gas, that’s nearly all in Europe. And primarily driven by the weather, it was colder, last year very cold, last year in Europe it was actually unseasonably warm this year. So quite a big difference. And many thanks for the question, I hope that’s okay.

Yes. Thanks, Simon.

Your next question comes from Mr. Jon Rigby from UBS. Please go ahead.

As you highlighted refining returning to profit, and it's not obvious from the data series on your refining margins why this quarter will be profitable and some of the historic ones wouldn't have been on the basis of macro. So could you just sort of talk a little bit more about the moving parts that got you sort of above the break-even point this quarter and how much of that is sustaining and how much is maybe temporary. I guess disposals might have an effect, right?

Both potentially, I mean that’s a good question, Jon. I think since the last quarter 2008 in refining, but it's so small, it's not material, and maybe all the old products there and these came from marketing and trading. And we also like it difficult correlate to the industry margins with our own performance. Two reasons for that, one is availability, we have the availability of the units was quite a bit higher than it was last year as the utilization of the unit. And we also in the North American market the actual coking margins were able to deliver were relatively attractive. So, basically it's good North American refining and the fact that our availability was much higher. I would just highlight though that, although we given traditionally refining split and marketing and trading together. We are divesting refining capability to the extent to that marketing sales of over 4 million barrels are becoming increasingly greater than the refining throughput of 3 million and decreasing. And our actual trading activity is how we join the molecule together. So, as we go forward it's really intimated value chain that drives us more so than separate (inaudible) refining. That’s what we may need to consider as we go forward. It's becoming bid of an odds play given the business model as evolving as we decline our refining base. Hope that helps.

Yeah, thanks.

Your next question comes from Alastair Syme from Citi. Please go ahead.

Hi, Simon. My question actually also relates to refining. I guess you're having the same difficulty. And if you look at the, you disclosed the cash flow in the quarter of about $4 billion, and if I'm right I think you were sort of talking about 2012 targets of about 12 billion overall across the downstream piece. So do we interpret therefore you're well above mid-cycle or are performances well on track on that 2012 target?

Another target question, thank you, Alastair. The overall products, cash from operations does benefit by definition. It includes the Cosan adjustment, so there's nearly $2 billion in there for the quarter that essentially is a one off impact that goes up and down. So, the underlying delivery is somewhat less. So, no we are not there yet. And technically we have not given a specific split of the Downstream contribution to the cash flow target for 2012. Yes, we clearly need to uplift from previous year delivery, but we have not given a specific split (inaudible) either. We retained the right to deliver to OEM bubble below mid cycle, I mean we are heading back towards mid cycle. I don’t think (inaudible).

Your next question comes from Lucy Haskins from Barclays Capital. Please go ahead.

Afternoon, Simon. Perhaps a bit of follow-through in terms of the downstream comment. You did actually talk about improving lose in the quarter but also improving trading. Could you quantify what the data was in terms of the trading contribution relative to 4Q? And then the second question was perhaps a slightly a bigger-picture question. Obviously sort of some companies are thinking about the opportunities to look at liquifaction within the U.S. Do you think that's something you might look at over time?

Thanks Lucy. We don’t split average rating, part of the reason I just stated our trading activity is not a separate desk, it's the way we optimize value through the integrated hydrocarbon value chain. So, there is an uplift in trading. It was a more volatile quarter, but it's only possible because of refineries and stock positions and marketing around which we can trade. So, overall marketing was backed out and above $1.1 billion of marketing and trading together. I think back in the fourth quarter it was more like 400 or so. So, it's quite a significant uplift overall and that reflect both, and I’m pretty strong marketing performance too. Liquifaction in the U.S., I think we said around the strategy presentation time, yes it's something where we could be interested in, are we actively pursuing a project at the moment though. It's a question of getting the capital cost down to a level of which it makes sense relative to the alternative means of monetizing gas. In principal LNG and the GTL and the gas to a transport or even gas to chemical is little bit ways of monetizing gas in against liquids prices. Yes, we are interested in LNG, and looking actively but it would more likely be in Canada than the United States. We still not been commensurate with the U.S. as talk through the potential and it is guarantee issues around export of gas from the lower 48. So, I think Canada is more likely scheme there. On GTL gas to chemical, gas to transport, these are all more ideas for the medium to longer term, if in fact gas to oil arbitrage opportunity remains strong as it is today.

Simon, I think you've quantified in the past that GTL probably is a go if you don't see gas prices much above 6, but it starts not to hang together sort of above 8. Can you give some order of magnitude in terms of liquifaction?

Well, in terms of GTL, we said that the Cosan gas to oil differential will probably make it attractive. We don’t show but this (inaudible) will sustain for a very long enough and sustainably enough to make that kind of investments. What we need to do is continue to work on the catalyst development and on getting the capital cost down. We will learn a lot from our own project in Pearl and Qatar. That will help us on the potential future efficiencies that will help us to answer that question better, but clearly there potential in the much longer term and it would require significant investment to help convert some of the gas exposure to liquids.

Your next question comes from Irene Himona from Société Générale. Please go ahead. Irene Himona - Société Générale: I had a question on the cash flow. I note you highlighted the delivery of 4 to 6 billion of cash including the disposals in the past sort of four quarters. So if I'm not mistaken, your target is 43 billion cash from operations excluding disposals, in which case on my numbers you delivered about 36 billion on a rolling four quarter average on an $87 oil price, so there's still a gap of 6 to 7 billion to the target. And my question really is trying to think about the timing of a possible dividend increase, should we anticipate that you will look at that once you hit the targets or given the external pricing environment which is substantially higher, could that come earlier than next year? And then my second question on upstream performance, I mean clearly it was weak versus expectations but also versus your own price sensitivities. Is the gap mostly the startup costs, in which case what should we anticipate for the rest of the year? Thank you.

Thanks Irene. Good question on FFO. Your first point your reference is absolutely correct, $36 billion rolling 12 months, $87 a barrel. So, still funding of the gas 6, $7 billion. You may recall that we always had Qatar it was further be uplift or around $4 billion at $70 oil price. So, these are the Qatar projects is yet actually contributing anything material in the first quarter. And at what point do we consider the dividend. While firstly it's the boards consideration on a quarterly basis. We are struggling a lot or the change the dividend policy last year to imply essentially it's the structured cash flow delivery. The dividend will grow in line with cash flow and earnings. We were not quite there yet, but we would also need to take a look at the balance sheet. The balance sheet is of course quite a lot stronger than not only it was a year ago, but probably a bit stronger than we actually expected it to be. And I expect the discussion to become more light as we go through the year. But we are not there yet in terms of structural cash flow growth. It's not technically going to be driven by the macro, but the balance sheet has effectively being put in much stronger place by the macro. And question on upstream performance in the quarter, I think there are few factors impacting but firstly, the startup on the (inaudible) costs around $400 million a quarter. It was less than half that level in the previous quarter and in Q4. So, it particularly high level of spend in Qatar and in Canada. In Q2 it's going to remain at a reasonably high level as well. Thereafter, it should start to fall off, we will up and running in Canada and Qatar gas will be up and running. Hopefully, a little bit of performance in GTL as well. So, it will start to come back. The couple of other factors probably worth noting for Q1 performance, we mentioned the downtime from the maintenance around 90,000 barrels a day and also the divestments and together they effectively relatively relative to last year costs us another $400 million. Then closer the 25, 30,000 barrels a day of Gulf of Mexico production, that we would otherwise have had, have it not being for the moratorium. And that’s not the straight reduction, but we would have been drilling and in fact have expected to grow production in the Gulf of Mexico. And so that 25,000 plus barrels a day has quite a significant impact as well. You put those cumulatively together, I think that explains what you might regard as a slightly weak upstream earnings. We feel reasonably stronger 4.6 underlying production is pretty good and the fact that I just described none of them were a surprise to us.

Your next question comes from Theepan Jothilingam from Morgan Stanley. Please go ahead.

Hi, Simon. Actually just following up on that question on E&P. Could you just talk about perhaps the delta on OpEx and increased royalties you're experiencing with the higher oil prices? And then just going forward through the year, I mean it seems you've had quite a lot of high-margin barrels off for maintenance. I guess in particular with Nigeria and Bonga, do you expect that to come back on?

Yes Bonga, it's a bit high margin, yes it was under planned maintenance and I think it's ramping back up again now. So, it will come back again. The changes in OpEx, cost inflation coming back into the industry we don’t actually see that yet and when we go to market, maybe it will come. As it comes, it will likely have more impact on CapEx than OpEx. So, our OpEx increases we will see increased OpEx as we go through the year as we start to incur OpEx for example, oil sands and Qatar. The unit OpEx once all of those projects are online we expect to go down a bit, because actually in particularly in Qatar [we use] OpEx is relatively low. And royalty tax other increases and it difficult to predict. I gave hopefully clear figures on the UK impact. Other royalty effects and tax effects is above on top of the UK effect to just over $100 million year-on-year. And it does vary from quarter-to-quarter. So, no I can’t project as particular impact there. We just try and manage our way through it.

Your next question comes from Mr. Marc Kofler from Macquarie. Please go ahead.

Yes. Hi, Simon. It's actually Jason Gammel from Macquarie. I just wanted to follow-up on a comment that you made earlier about your LNG portfolio having three projects in Australia that essentially would fulfill future market demand. How do you go about prioritizing the marketing of those three projects, and would any of them be more appropriate say for just taking into your own portfolio versus a long-term contract with a single buyer or a group of buyers?

Thanks Jason, good question. The three projects we talk about Gorgon which is already under construction, Prelude which hopefully is close to a final investment decision, that’s the floating LNG project and the third one is the CPM LNG project coal bed methane or coal seam gas. And which is in the Arrow project which is associated joint venture with PetroChina and that shows share of production in all three projects between 3 and 4 million tonne. And we have about 10 million tonnes in total of Australian LNG to market. So, all of those volumes are effectively to be sold from the project to Shell and Shell will then market to customers. So, in practice we are and have some contracts we are seeking it more that are not so-so destination specific, where we sell to a customer and they are in different source of the LNG. So, we are effectively taking them into Shell portfolio. And that’s why the Australian projects make such a big difference to our overall portfolio because by and large the majority of our existing production is termed lined in from one source to one destination customer. And does that cover the answer, actually determines how we prioritize.

Yes, it certainly does. And I guess just as a follow-up would you expect that the flexibility that it gives you would give you the opportunity to capture spot market dislocations like what is going on in Japan right now?

We always of course subject to our transfer pricing and other issues. And that always need to be done in a very transparent fashion. Just on Japan by the way, we did not take advantage of the on price at all, everything was done onto normal contract price as they would have been wholly inappropriate to take advantage of that situation.

Your next question comes from Jason Kenney from ING.

Hi, Simon. Congratulations on the good progress this year so far again.

Thank you, Jason.

So I've got two questions on Brazil. The first is to ask if you've got anything that you can say about Campos Basin exploration fund Petrobras announced this morning and maybe remind us what is next offshore Brazil. The second staying with Brazil with the rise in JV, I wonder if you can comment on the Brazilian press article in Valor that suggested that Chairman, Rubens Ometto has negotiated a 25 million per annum pay package from Shell directly for ten years there.

Thanks Jason. Well I can’t comment generally at the Petrobras announcement of that and actually we read it. Our actual activity coming up this year is you may recall BMS 54 [blocked] last year the Qatar [De Mayo] discovery is 80% Shell. We expect to drill at least a second well this year on that block on those, what is an independent prospect within the block. We will need a second appraisal well on both of those prospects before we really know what we have in that particular area. The (inaudible) project is progressing, we will be doing more drilling there. And we have a couple of other wells being drilled on that behalf by Petrobras that we have both exciting time offshore for than Brazil this year. And rise in JV reports on Rubens pay package. Rubens compensation not as remuneration that’s an effective rate from the joint venture. He was a major shareholder of Cosan, a big obviously a supporter of the deal. Not a Shell employee. And those (inaudible) either it's not necessarily it's not really a decision for shareholder it's decision for the joint venture. So, that’s all I can say.

Your next question comes from Mr. Jack Moore from Harpswell. Please go ahead.

A couple kind of big-picture questions. I was wondering first with respect to service costs, what are your expectations over the next year? I think in particular one of the large three oil service providers has focused keenly on improving their margins significantly, and I was just wondering how you see your costs escalating over the next year. And then in the long run what are your expectations with natural gas kind of on a global basis? Do you see prices more of a global price or do you see kind of pockets where there will be dislocations based on supply and demand in that specific geographic region?

Thanks Jack. I’ll try and cover it briefly because they are both quite complex subjects. Service cost generally as I mentioned is quite a lot of talk about it's potential inflation, but we don’t actually see much yet when we go to market. I imagine many of the companies are focused on improving their margins, we may recall couple of year's ago, post credit crunch. A lot companies set a lot of that going back to the suppliers and demanding reductions immediately, (inaudible) to do so in some cases. As you think you may recall that we can do that, we run back and what we hope is a more constructive discussion that said how do we work together with some of that suppliers including being what I imagine of the big three. And how do we constructively manage for the benefit both of us the way through volatility in the price cycle, which is not actually a much help to either of us. And we did come out of that was what I think is most better improved contracting strategy and supplier relationships. And agreement that provides both some long-term security of supply for the supplier and as for us last volatility and the cost of the services. They will not provide 100% protection against another doubling or tripling of overall cost, but they will help us to ensure that we have access to the services, and hopefully getting the 18 from the serving company which is usually their biggest driver of value for us. A good relationship have a lot of value. So, we are not seeing that significant a change at the moment and we think the agreements we have in place and most of our main suppliers will be robust against in inflation. That’s right longer run, clearly where a gas becoming a gas company we probably will reduce more gas this year. They are very important question for us. Three different markets, North America will remain [divorce] from oil pricing, it will be driven by supply demand and alternative uses also basically we believe on the top end alternative sources of fuel for power. So, we plan on the basis of the range of gas prices 4 to $8 at the million cubic feet. And we hope will the global gas market develop well north of the core that’s not our expectation, the other margin that will be movement of molecules from both directions from North America to Asia. But the Asian market we see medium and long-term remaining quite closely linked to oil prices. In between Europe, gas market has shifted already from what used to be 60% oil liquid related contracts. And that was more like 40% with the rest being spot oil or (inaudible). That trend may continue, there is still a market for longer term, oil price linkage depending on the customers who are richer. But the (inaudible) in the past quarter alone were 1.3 times higher than the Henry hub price. So, the fact that spot in hub prices may become the norm to North Texas remain that will be a lot lower. It's just a question of what kind of volatility and what kind of price arrangement does the customer want. So, we see three market LNG will arbitrage between them, but probably more on the margin than it will do structurally.

And that's very helpful.

Are next question comes from (inaudible). Please go ahead sir.

Hi, Henry. This is Bert from the Netherlands. I was wondering about the upstream profitability. There was just a very marked jump-up in the Q1 in the area other. You said Qatargas 4 only gave a small contribution so far, so I wonder this is mainly Russia or has Majnoon already reached some threshold to generate some profits?

I will tell you it's not Iraq but in essence especially higher oil LNG realizations. We don’t lately other areas, you can think of it being a [slave] from Africa to Middle East through to Russia. So, I guess it does include Russia, but it will include the LNG from the Middle East also from Nigeria. And that’s really was driving it.

Right. And the second question is you talked about Cardamom. I understand that as of about ten days ago ten permits had been issued for the Gulf of Mexico. Undoubtedly you are among those. Do you have any sort of prediction as to what sort of number of permits you will have held by the end of the year?

There is good opportunity just to reiterate (inaudible). We had 8 applications in including new exploration plans. We had two of those explorations plans now approved and one approved and one accepted as complete. The approved one is Cardamom, and the Appomattox plan has accepted as complete there on the consideration period. They are the only ones so far to have reached that complete stage. So, that’s the new well. The Cardamom first drilling permit was issued. We started drilling three weeks ago. So, we are actually drilling exploration wells in the Gulf of Mexico now as the Cardamom prospect which is good news. Separately we also had approval for one of the Perdido development wells which we are also about to drill. We got five floating and drilling units. And we are drilling off some platforms work such as workovers and recompletions. Of the floater that we got, and three of them are already new regulation ready and one is closed. And we are paying down to Brazil for a while. So, we are getting back to work but it is still slow progress. We said we expected to loose effectively 50,000 barrels a day of production this year in the Gulf, relative to what we otherwise would have achieved, if there had been no moratorium. The rate at which we are coming back we stick with the 50,000 we don’t change that, but we would like to see the rest of our applications progressing through as well. But it's good to see that there is forward progress and that we are able to start drilling again.

Your next question is from Iain Reid from Jefferies. Please go ahead.

Two quick questions. The provision you made for the UK tax price seems pretty small in relation to your size and certainly a lot smaller than your UK competitor announced yesterday. Is there some sort of tax relief there or kind of a different treatment do you think you're applying there? And secondly on Qatar I just wondered if you can remind me of what percentage of the LNG volumes are long-term contract linked to oil from there.

So, I thought of the second question, we have not actually given the figure it's just indicate in the past though, originally half the volume we target in North America and half in Europe. And Qatargas does the market and we are doing an excellent job in redirecting not just shorter but long-term as well. That gas into Asian market, and the Middle East to South. So, we are in effecting quite an uplift compared to what we would otherwise (inaudible) exporting into North America. The exact proportion is evolving as those contracts are being put in place by the Qatar, but we are very pleased with what we have been able to achieve so far. And tax provision, it's interesting well we have to work a bit on this. We haven’t taken a provision yet, the provision that we have taken the big change will be next year in the first quarter. The reason e haven’t taken a provision is, basically the impact is deferred tax liability that we carry as a result of capital lines have been different to depreciation. And the deferred tax asset that we carry those reflects the future decommissioning liability. If those two are of the similar size which in our case they are, the change in tax have no or little or no net impact which is the case for us, they are very similar in size and no material net impact in the first quarter. If in fact that liability and assets are of a different size yes you would get a one off impact up or down in any given quarter. So, I can’t speak for others, but that’s what our situation is, then of course is a event and an uplift every quarter of the current tax. The year's provision in Q1 happens when effectively we have increased the deferred tax asset on the retirement obligation from the 50 to 62%. When the legislation is enacted which is likely in Q1 next year, we will have to reduce that 62 to 50 and impact is likely be around $500 million. It's a bit complex and technical but hopefully that helps.

Your next question comes from Lucas Hermann from Deutsche Bank. Please go ahead.

Yes, Simon, afternoon. I hope you're well. I could have a laugh and ask you to repeat those last comments but I think we'll move on. Just a couple of questions if I might. Firstly, can you talk a little bit about CapEx phasing? The CapEx this quarter including associates looks very modest relative to the guidance. And secondly I wonder if you could talk a little more around the chemicals operations where if I look at cracker margins they're very high and yet your profits have come back modestly. And in particular what's happening with Bukom and why Bukom down for such an extended period of time.

CapEx phasing, yes it was effectively quite low. We gave an indication and we retained the same indication that we would likely spend this year $28 billion on organic investment and too on acquisition. And the two was the completion of the Reizen deal in Brazil. So the going rate would be 7.25, the actual rate in Q1 was around 4. And couple of issues really want just typical phasing particularly in the downstream tends to be back ended and you can see that in the downstream CapEx figures. Secondly, on the upstream we are seeing the CapEx coming off on some big projects. And while we expect to take some FIDs [they not all] taken yet, so I would expect on the bigger FIDs that will, which I mentioned earlier they will see enough take in the upstream spend as we go later through the year. On the chemicals margins, Asia was the main challenge for us where potentially we could have done better. The issues Bukom are just basically related to the startup of the plan still working to optimize the performance there. And then the real comment on the underlying issues hope to be backup and running in the not too distant future.

I mean, Simon, is 28 billion in CapEx a realistic number for you now?

Do you mean annually or this year?

Well, I mean this year, yeah. And if you could tie that in with your thoughts on U.S. gas expenditure, as well.

(Inaudible) somewhat that is realistic. We will have to try quite harder I guess to spend on that rate inorganic, particularly the other point that you raised on the U.S. gas. We have stated in past week, we got the portfolio spend somewhere between 3 and $5 billion per year on this activity typically our investment of the strategic plan also something in the middle of that range. It's likely or certainly that early planning is more at the bottom end of that range while the gas price stays at $4. But there is still quite some potential on the more liquids rich part of the portfolio. And just of the FID, it seems like Prelude, Cardamom and the two UK projects, (inaudible) and the Athabasca debottlenecking, they all started to take up the slack and fairly quickly as we get into the second part of the year.

Your next question is from Mark Gilman from The Benchmark Company. Please go ahead, sir.

Simon, good afternoon. I had a couple of things. I think one of the slides indicates that in the first quarter you acquired some additional Rockies and Marcellus acreage. Wonder if you could quantify that both in terms of acreage and cost. Would also appreciate some commentary on what the Americas unconventional gas production looked like in the quarter and how it compared to prior periods.

Thanks Mark. We picked up a little bit more acreage in the Marcellus and around the North American plays, but it's not be in that material in terms of what we are thinking us relatively underdeveloped should we say, so we are not being a [top goaler]. And the unconventional gas production during last year we grew to 1.2 Bcf a day by the end of the year. Of course, we are now seeing the impact of the investment in South Texas so backed just above Bcf a day or 180,000 barrels a day oil equivalent. It's drop back again, but we expect that figure to grow as we go through the year, particularly out of Haynesville, Grand Birch, and laterally into the Marcellus.

Okay. Simon, if I could, I was confused by your comments during your direct remarks on the UK tax impact and why the 2012, 100 million per quarter number ostensibly at the same price level was so much higher than what you envision for the balance of this year given the March 24th effective date of the increase.

As partly have pick up in the expected profitability in the UK just a factor of a variety of issues, production, prices, etcetera. But that is how it is (inaudible) 100.

Your final question comes from Alejandro Demichelis from Merrill Lynch. Please go ahead. Alejandro Demichelis - Bank of America/Merrill Lynch: Yes. Good afternoon, Simon. Just one quick question on the Gulf of Mexico. You mentioned the situation about the barrels and the 50,000 target still unchanged, but in terms of cost what we can see in terms of you coming back and drilling again there? Is it going to be any kind of reaction on cost there?

Thanks for the questions, good point worth noting. And we actually did take another $60 million in the first quarter on cost, as we go forward, the cost impacted primarily in capital not OpEx. The new regulations as we see them and interpret them, we don’t expect to add material cost as buy and large they reflect the practices both in design and operations that we were already applying. And the unknown factors there were lot of the reports that have come after date contain recommendations, they don’t actually, change of legislation. So, it's possible the regulation still have some room to develop, also I’m entirely sure has some of the regulations will be interpreted. It is possible that some of them will make it take longer to drill a well. And we are still paying the same spread rate, and it could be a $1 million a day on a rate plus the support activities. So, that we don’t know yet, because we need to get a bit more of experience, but buy and large as the regulations adjusted they reflect [prices] and for example Europe and the standard that we are already applying.

You have a one final question from Sergio Molisani from UniCredit.

Yes, good afternoon to everybody. Two questions if I may. The first on the Pearl GTL, on the occasion on the Qatargas 4 you gave a sort of guidelines for your operating cash flows from Qatar based on the price scenario 50 to US$70 per barrel. And if I remember well the guidance was 3 to US$4 barrel more or less until 2020. Can you give us an idea of what could be this cash flow on a US$100 per barrel oil price scenario? And the second question is on CapEx. Your US$28 billion guideline includes so it's gross or net of the (inaudible) $1 billion of CapEx cost that you guided for considering that if I understand well these are startup costs or investments that you are not allowed to capitalize spending the startup of this project? Thank you very much.