Shell plc (SHEL) Q3 2010 Earnings Report, Transcript and Summary

Welcome to the Royal Dutch Shell first quarter 2010 results presentation. Firstly, please take a moment to read through our cautionary statement. I'll take you through the results and then there'll be plenty of time for your questions. Our current cost of supplies earnings for the quarter excluding identified items were $4.9 billion, an earnings per share increase of over 85% compared with the third quarter of 2009. And the results rebounded from year-ago levels, driven by both execution of our strategy and more favorable industry conditions. I'll give you the details in a moment, but both Upstream and Downstream earnings have increased substantially here in fact approximately doubled. This is a better performance from Shell, and the quarter underlines for delivering on our strategy, which is all about shorter-term performance focus, delivering the growth targets for 2012 and creating new options for the future beyond that. Our continuous improvements are going well. We took out $3.5 billion of underlying cost in 2009, and to the middle of this year. And this year-to-date we've completed over $2 billion of asset sales from our non-core portfolio. We are in a delivery window for new growth. The third quarter production increased by 5%, and we started up new production at the end of the quarter in Canada's oil sands and mining. Building for the future, we took the final investment decision on two new projects in the deep water. And we made $5.5 billion or we actually completed $5.5 billion of acquisitions in the quarter. So let me give you a few more details on the results, starting with the macro. We do have quite some seasonal business for example, natural gas, where the factor such as wet weather can be an important driver. So we have to look at these macro trends and the earnings that are related to them on a year-against year-basis to normalize for that. If you look at the macro picture compared to the third quarter last year, oil and gas prices did increase from a year-ago. However, the spread between oil and natural gas realizations remains wide. And this is mainly driven by the more rapid increase in oil prices compared to North American natural gas prices. That said, we have seen a year-over-year increase in European natural gas realizations, the actual price we achieved. And this has reversed the declining trend in the first half of the year. This of course is positive for our earnings. Chemicals margins have increased in most regions against the third quarter last year, and we're seeing good earnings in this segment. Refining conditions remain challenging, although margins have actually improved from a year-ago. Turning now to our earnings, the headline current cost of supply earnings of $3.5 billion for the quarter included identified items of $1.4 billion. We normally every year test our carrying values in the third quarter, carrying values on the balances sheet that is. And the results today they do include impairments as a result on upstream and downstream positions. Most financial analysts do tend to set these items aside and they'll all confirm because of the underlying results. So the third quarter earnings excluding the identified items were $4.9 billion, earnings per share increased 86%. The cash flow from operations for the quarter was strong at $9 billion, the dividend for the quarter $0.42 per share. The quarter for higher earnings in both upstream and downstream, so let me talk a bit more about that in detail. Firstly in the upstream, excluding the identified items the upstream earnings increased by 106%, more than double, to $3.4 billion in the third quarter. The main drivers in these results were higher oil and gas prices, increased dividends from more of LNG joint ventures and our underlying program to increase volumes and control costs. The production increased by 5% Q3-to-Q3. Production from new fields and field ramp-ups of relatively new production was around 180,000 barrels a day of oil equivalent. And not more than offset the field decline that we say the natural consequences at operations. Our LNG, liquefied natural gas sales volumes grew by 22% over the past year. This was under-pinned by Nigeria LNG, where the gas supply picture to the LNG plant has improved. We essentially reached full capacity at the LNG plant, about six trains, 22.5 million tons at random equivalent by the end of the third quarter. Now let me also update you on our activities in the offshore in the U.S. and Gulf of Mexico in the light of the drilling moratorium following the BP Macondo oil spill. We have continued some of our development activities during the drilling moratorium, for example, with a restart of the Perdido platform in September, following some maintenance activities there. However, we had five floating rigs, four of them in the Gulf and four platform rigs idled in the United States during the third quarter because of this moratorium. So in the quarter's financial results, we've taken a $59 million charge for the impact of having these rig idled. This was taken as an identified item, and that brings the total for this year so far to $115 million. There will likely be further charges in the fourth quarter results. The moratorium and the delay to our drilling program is an opportunity loss for Shell. We've seen 230,000 barrels of oil equivalent per day production in the Gulf of Mexico in the first nine months of this year. And that's 10,000 barrels a day lower than it would have been without the moratorium. And although that moratorium has been lifted, we do expect a knock-on effect on future production, because of the drilling delays we've had this year. For the next year, for 2011, we're currently expecting around 220,000 barrels of oil equivalent production a day in the Gulf, and that's around 40,000 barrels a day below the plans that we previously set before the moratorium was put in place. There could be further impacts in 2012. Turning now to the downstream, excluding the identified items, the downstream current cost of supply earnings increased quite substantially from the third quarter last year to $1.5 billion. Chemicals earnings driven by both execution of our strategy and by the industry margins, and our performance included the performance over the activity, the new capacity that we've added in Singapore, selling to the Asian markets. And investments made in the United States to increase our capability to crack lighter feedstock, essentially gas feedstock in our Gulf Coast facility there. There was some improvement in our refining performance, but the refining conditions do remain difficult, especially in Europe, which causes an important refining centre for us. And we are still meeting losses in refining around $90 million in the quarter, that's similar to the second quarter this year but much lower losses than we saw last year, where they were around $450 million in the third quarter. Our marketing and trading earnings increased from a year-ago levels, this reflected higher earnings from lubricants, and partly offset by slightly low in trading and retail contributions. But overall a very strong marketing and trading contribution. Work updating that we currently experienced some downtime in the catalytic crackers in Pernis refinery in the Netherlands, and the Port Arthur refinery in the United States were in the maintenance period and doing some repair. So we do expect to see a small impact for this in the fourth quarter results. So those are the earnings. Now, just turn to the cash flow. Our cash generation on a rolling 12 months basis for the last four quarters was $35.3 billion, including $3.9 billion of divestment proceeds. And broadly speaking, the cash flow for the first three quarters of this year or nine months of this year was higher than the whole 12 months of 2009. Back in March, we stated that we are targeting a 50% to 80% increase in our cash flow from operations, compared with the 2009 baseline by 2012, so over there years, 50% or 80% depends on whether the oil price were to be $60 or $80. Our acquisitions in the third quarter this year totaled $5.5 billion impacted in the capital investment. And this, combined with our on-going capital spending program, resulted in a slight increase in the balance sheet gearing in the quarter, and that rose to 19% at the end of the quarter, compared with 17% at the end of the second quarter. And so that compares well with the 0% to 30% range that we set as the range in which we planned our financial framework. We continue to watch the cash position and balance sheet very closely and put a particular emphasis within the company on cost management and capital efficiency. And we made good progress with portfolio development in the quarter. We've now started up five as of the 13 new projects coming on line in the 2010, 2011 timeframe. This now includes the start-up of the 100,000 barrel a day expansion to the Athabasca Oil Sands Project with a second mine site called Jackpine. Production here will ramp up during 2011, as the new capacity at the Scotford Upgrader also comes on stream, processing these barrels from heavy crude into higher value lighter products. Having two mines in service, that means we can start to reduce our unit costs there from the synergies and the scale that we have. And we'd expect to reduce those production costs by around $3 a barrel across the whole mining activity. Looking beyond 2012, we have made progress crystallizing some of our longer-term options. We took final investment decision, what we call FID, on two deep water projects. In the Gulf of Mexico, we launched the 100,000 barrel of oil per day Mars B development. And in deep water offshore Brazil, we took an investment decision on the second phase of the BC-10 project, which came on line in the past 12 months. Turning now to acquisitions and disposals, this is an important part of our focus on continuous improvement of the portfolio. Firstly on acquisitions, we made progress on several bolt-on deals in the quarter. East Resources takes Shell's North America tight gas potential resources to some 40 trillion cubic feet completed in the quarter. Arrow Energy, which we bought together with PetroChina, is a coal bed methane play in Australia that can support 6 to 7 million tons per year of LNG for export to Asian market. And in the downstream, we signed binding agreements with Cosan to form the marketing and sugarcane-based biofuels joint venture in Brazil. We're expecting to book a capital contribution of around $1.6 billion on this particular transaction in the early part of 2011. On the asset sales side, we've agreed to sell our 13,000 barrel of oil equivalent per day late-life position in Statfjord Field in Norway for $225 million. And we completed the disposal of three leases in Nigeria, which actually today produce around 15,000 barrels of oil equivalent for Shell. We are making selective investments in Nigeria, to strengthen the long-term position there, and you can actually see some of the impact of that in the third quarter results. But at the same time, we're focusing our footprints in the country onshore and encouraging more involvement by indigenous Nigerian companies. We do that through the on-going divestment program. On the downstream asset sales, we agreed to sell our 90,000 barrel a day Heide refinery in Germany to Klesch. We agreed that during the quarter and we've continued to market other positions and hopefully you've seen it yesterday, we announced agreement on the sale of our downstream asset or business in Sweden and Finland, which includes the refinery in Gothenburg. Overall, these disposals that we see in the quarter, they're all part of the overall target to sell some $7 billion to $8 billion of assets over the two year period 2010, 2011. And we've done just over $2.2 billion of that so far this year. So this as to reiterate is a value-driven program. No fire sales and its all part of a continuous improvement strategy. So, let me summarize. Excluding identified items, earnings per share increased 85% from the third quarter of 2009. Performance in the quarter very much underlines we're delivering on our strategy. We're making good progress on all three of the strategic themes, the shorter term performance focus, the medium term growth delivery from new projects, a longer term creating future new growth options. Our priorities remain for a sharper delivery of that strategy. We aim for profitable and a more competitive performance. We believe we're making good progress against these targets and we're on track for growth. With that, I'd like to move to your questions. Now, operator, please could you poll for questions.

(Operator Instructions) The first question comes from Guy Chazan of Wall Street Journal.

I'm just interested in the figures you quoted about the knock-on effect of the moratorium in the Gulf of Mexico. And the fact you see around 40,000 barrels per day low production for 2011. Could you give a bit more color on that? I mean why are you seeing that drop? And just may be a little bit more detail on what kind of impact the moratorium has had in terms of knock-on effect? And also whether you think that the whole system has sort of managed to kick into gear and get up and running fast enough after the moratorium was listed?

The answer is still evolving I think is the right response. Firstly, what I just stated; the knock-on effect for next year, we anticipate a loss for Shell. Our share of production around 40,000 barrels a day. We're still one of the major operators there of course. So that's one of the more significant figures you will hear. What's driving that? Well, for example, we brought on the Perdido project earlier this year with seven wells producing. We have a drilling program plan to increase production from Perdido. Perdido is currently operating around 10,000 barrels a day, it's capacity is well over 100,000 barrels a day. We can't drill the well, so we can't bring the production up. The same applies to one or two other opportunities. And it's also impacted on our expiration program where we've been extraordinary successful over previous years. Specifically, we've not been able to drill development wells on our Glider and Brutus platforms and on our Auger platform. Now, all of that was planned this year. May be we can catch up a bit next year, but we can't rely on that. As the moratorium was lifted, we immediately submitted applications to drill which we've been preparing. We've looked closely at the new regulations. We have rigs and equipment, blow-out preventors for example that we believe meet the new requirements and the permits are now with the new Bureau for Ocean Energy Management for considerations. What we've not sure of, typically those permits used to take about 30 days to progress. Obviously, the new regulator authorities will be taking a very close look. We expect that the first applications in the first well that they give support for. So we will not be surprised if it takes a bit longer than the 30 days for the first few wells. We do not know at what level of preparation they already are, and therefore we can't say whether the 40,000 will increase or not. It will depend, literally, on how quickly the permits are processed. There's probably not much more I can say in the current environment. What we're also aware of, of course is that the President's enquiry or the Presidential enquiry will report out in January. And we hope to learn a bit more about facts and information. And there may be further considerations from the regulators about the requirements that they will have there which we will seek to meet.

Just about Alaska. What is going on, what is the latest state of play with the plans for drilling in the Chukchi Sea?

We have two types of acreage in Alaska. And both the Beaufort Sea and the Chukchi Sea. The moratorium in practice extended to Alaska. We had a rig ready to roll-in, in 2010, we were not able to do that. And then the cost of not being able to do so were included in the figures I quoted earlier. We have resubmitted applications for the Beaufort Sea for 2011, not for the Chukchi Sea. We again will await the response from the regulator authorities.

The next question comes from Fred Pals of Bloomberg.

Just wondering if I'm correct, over the past 18 months, Shell hasn't increased dividend payments. And I'm just wondering whether we'll be able to get some guidance on when you think you will able to start raising it again, and whether it will be 2011 or 2012, or when you debt is becoming a bit more stable?

Earlier this year, we did update the dividend policy. We stated we wanted the dividend reflect the underlying earnings in cash flow situation of the company as that was a change from previously increasing in line with (inaudible) on an annual basis. You're right, we've held the dividend constant now at $0.42 for 18 months. I think it's fair to observe that four of our European competitors have actually cut their dividend the last 18 months. But our dividend yield and our payout ratio are much higher that our U.S. competitors. We've no intent to cover dividend. We might want to see it in a more competitive basis overtime.

But you can't give an indication on when to increase it again?

I think our payout ratio was probably a little high in the past. And our dividend yield is certainly extremely competitive in the moment as I mentioned with everybody else cutting and the U.S. companies having a fundamentally lower dividend payout policy. It's a very competitive position we believe at the moment.

The next question comes from (Michael Paisan of Devoux Grant).

I had a question following up on your remarks about Nigeria. You talked about refocusing and divestments accordingly. Could you say a bit more about criteria for fields that you want to get rid of?

We got three businesses in Nigeria to just be clear. On shore oil and gas production through a joint venture called SPDC, Shell Petroleum Development where we're 30% holder and operator. And NNPC, the Nigerian National Company owns 55%. We have an off shore deep water business which is pretty successful. And we have the L&G business. Our divestment program is entirely focused on the first of these, the on shore drilling venture. We have 30 licenses; we have the largest geographic footprint in the delta area. We were strong just about every where (bar) the East. So we're in the south, the west, the northwest and the central area. We have our core oil and gas production very important to us, particularly in terms of supplying gas to the NLNG plant. Geographically, some of the west, the northwest blocks are more isolated and much less developed. I mentioned the Nigerian company owns 55% and all of their share of the funding is government approved and very limited. When we look at the future prospects for these blocks, we think it relatively less likely that the government will make funds available to develop these blocks and that these blocks may well impact us maybe more valuable to others particularly if they have Nigerian or indigenous owners and a greater involvement of the local community in terms of helping develop the blocks. So these blocks may well be worth more to other people than they are to Shell. Many of them have potentially significant resources in place, but today, relatively low production and a low level of infrastructure. So it makes sense to us to reduce our footprint. We still have some very important activities onshore. We want to focus our investment where it makes most sense to Shell. I hope that gives you some of the context. And all of the blocks that you've heard about are selling fall in the category that I just described.

The next question comes from James Herron of Dow Jones.

Looking at the BP assets sales they've done recently. They've good prices for what they've sold it seems. In many cases got more by selling assets than they have sitting on their balance sheet. Would you say that the same could potentially be true for Shell? And that perhaps Shell could realize greater value for its shareholders by embarking on a more ambitious divestment plan that the $7 billion to $8 billion you've outlined for 2010-11?

We are divesting because of the wish to focus on areas of competitive advantage that are aligned with our strategy. We're not divesting because we need to. It's not a question of needing the cash, but it does help upgrade our capital efficiency in terms of where we invest new dollars. The sales that we have been making in the down street we typically made a profit. There is a profit in the identified items on some of the sales in the upstream in the quarter as well, in Norway and Nigeria. So we are doing some good transactions, we're releasing value for our shareholders. But we're doing it in a controlled way at the margin which at the time, we have actually divested $30 billion of assets over the past five years. So we're not in some kind of fire sale or need to act mode. But we are consistently upgrading our portfolio and recycling cash and value back into areas where we believe we're more competitively positioned.

The next question comes from Robin Pagnamenta of The Times.

I was just wondering if you could say a little more about these final investment decisions that you made on the 3D water projects, MARS B and in Brazil? Has the accident in the Gulf of Mexico affected your view of the economics or to water drilling at all? And how significant do you the sort of long term implications of this accident will be for Shell in the water industry?

First with the recent investment decisions, MARS B. We've been looking at this project for some time. It's essentially a second major platform in the MARS base scenario where we've already produced over one billion barrels. What this platform does is two things, it develops a couple of new fields, South Deimos and West Boreas being the main new fields, but it also helps enhance production on the main MARS field through water injection. Incremental production, 100,000 barrels a day. Actually in cost terms, good time to go to market. Particularly with the fabrication capacity and some of the equipment suppliers in terms of catching a window of opportunity should we say. So the economics will be a bit better than they did six, twelve months ago. PHASE 2 for BC 10, BC 10 is actually 100,000 barrel a day capacity facility. It's currently producing 85,000-90,000 barrels a day from the first phase. As that production declines, naturally, we intend to bring in new fields in the block to keep up the production as close as possible to that capacity. That's the basis for the second investment decision there. So with cheap production in three, fours time replacing the decline in production, but the facilities already exist. Both projects are relatively attractive economically. More generally, what is the implication? Well, obviously, we look at the fact that they've merged. We look at the interpretation by regulators particularly in the United States. What are the implications? It is our belief and our current design standards and our current operating practices are inline with only a couple of minor updates with the new regulations as they currently specify to the United States. Now, that's not to suggest that the upcoming enquiries and other sources of information might move the bar again. But given that our current operating and design standards are pretty much in line, then it shouldn't make that much difference in cost. What we are not sure about is what will be the overall level of activity and what will be the impact on supplies of equipment or contractors working in the industry, or whether other regimes other than the United States make changes to their regulatory requirement. For example, we think the European requirements, safety, case-based, the principles or performance-based guidance that apply in Norway and the U.K. and in the Netherlands is very fit-for-purpose approach. And obviously our costs reflect the requirements of that system today. So it's still a little early to say strategically what the impact on cost might be. The impact on access, particularly in the Gulf of Mexico, whether some smaller players chose not to back uninsurable risks, it's a little early to say, but we do expect some players to be thinking casually about the risk reward balance of deepwater drilling and participating in offshore projects. Still early to say, do expect there to be some impacts but directly in the short and the medium-term, not a significant impact on our cost base.

The next question comes from Tom Bergin of Reuters.

I had a question just about the identified items., You spent about $1.1 billion there and it doesn't really (seem) what it is? So the estimate's a fair value of accounting and commodity derivates. But asking just sort of this regard, can you maybe give a bit more color on those charges and the (inaudible) should be this regards. Also, just a question about your refining there? You mentioned there is a small profit in the refining division. Can you tell me about your European refinery situation? I am wondering if you're making any money there at all and also hat your investment plans would be there, whether there is any sense in continuing to invest in those facilities. And then, finally whether that might have any impact on the safety of those facilities? One or two places, the workers have complained about that.

I'll try and cover all those issues. Identified items, there are four things I'll talk about. Firstly, every year we are obliged to look at the carrying value of our assets on the balance sheet. It's called a value erosion review, it's an accounting requirement. We choose to do this on the third quarter. We de-couple it from the fourth quarter activity simply to smooth the activity during the year. So we look at every single asset. Regard to cash flows and revenues compared to the carrying value on the balance sheet. Normal process. There are two major areas of impact this year. The first, perhaps not unexpectedly as in downstream refining are at $900 million after-tax impact of or/and the six different refineries. This reflects either a less optimistic expectation of future revenues or a more pessimistic view of what we need to spend on the refineries, partly related to your second question, or decisions to close or move the refineries to the terminal basis. So not unexpected, given the performance of refining over the past couple of years. $1 billion in the upstream of impairments were taken in Canada for heavy oil assets that were required with the Blackrock acquisition by Shell Canada when they were not fully controlled by the Shell group back in 2006. These are all in-situ production assets. In fact, most of them are not producing. The impairment reflects two things; one is quite a detailed review of the subsurface technical capability of the assets. And they look overall less good than we previously expected based on the original acquisition. And secondly, hopefully you would have seen a pretty clear strategic focus about where our priorities are in heavy oil. They are in the mining area, where we've got the current expansion up and running, they're in the debottlenecking of the facilities where we see another, maybe 90,000 barrels a day potential. They are in Peace River Carmon Creek project which is an in-situ, 100% (inaudible) Shell opportunity. So those are our priorities, which means that the Blackrock in-situ assets are much lower than the priority list which leads to impairments. So there's about $1 billion there. The third item I would raise is, they're offsetting that. There are some profits, paper profits on asset swaps particularly swap we did with (Hash) on Norwegian, U.K. and Gabon assets where accounting rules oblige us to write these assets up to the swap value, which creates a virtual profit, paper profit. I don't particularly like to see this in the accounts, but those are the rules. And the fourth item is, on every quarter we're faced with revaluation, mark-to-market of some of our trading positions where the accounting treatment is different from the physical stock that we hold against those trading positions. So those four items, net impact as you state $1.4 billion. Refining, we lost just under $100 million in refining this quarter. Roughly the same as the second quarter this year, but better than we were last year where we lost $0.50 million in the third quarter. Europe, of the three main markets is the weakest. Asia-Pacific has picked up quite a bit in the last six months and the U.S. remains challenging. Europe most definitely is still in a loss-making situation overall. Will be helped by, for example, sale of Gothenburg refinery in Sweden and Heide refinery in Germany. Our investment plans. One of the reasons we are selling refineries (inaudible) which should take us from about 3.8 million capacity a day to 3.2 million by the end of the year, a 15% reduction in capacity targeted. Quite a significant reduction. One of the main reasons driving that is, there are quite significant investment requirements for refineries to maintain two things, one, process integrity and two, product quality. We're currently investing in Europe on one major project which is the desulphurization in Pernis in the Netherlands. But we are continuing to invest in process integrity and a lot of small projects. We always put this first in our allocation of capital. Unfortunately for us, that means the most of the capital we are prepared to allocate to the refining sector is in fact going into process integrity and product quality and probably not enough into margin enhancement projects. That covers everything.

The next question comes from (Matthias Schaeffer of Dutch Financial Daily).

I understand you are looking to divest some blocks in the northwest of Niger Delta. How much of Shell's potential onshore in Nigeria is involved out there? That's the first question. Second question is, I'm a bit confused about how the situation in Nigeria is at the moment. You seem to say that it's getting better. Safety has been approved. But as you know that your sustainability index removed Shell from the index because of Nigeria, so they have a different opinion to that I suppose. Do you agree with their opinion , or don't they see it in the right way? And the third question is about the charges in the Gulf of Mexico. Is there any way you try to get this money back from BP, for example?

The Nigerian portfolio we blocked earlier this year and we just (completed) one block in the quarter, that's four out of 30. There is potential for future blocks, and also some speculation in the (inaudible) future blocks. But I can't comment on specific activities. All I can say is, it is going to be a relatively small proportion of our current approximate value and then reiterate the (strategy) is targeted. The blocks where we fail, other people will be able to invest more to generate more value through the indigenous involvement. So this is not a wholesale withdrawal. We desire investment on some very important oil and gas producing assets in the Gulf. And in general in the country, we've seen the security situation improve. We have brought on-stream three major projects recently, the Gbaran-Ubie gas project, the EA offshore activity which is actually shallow waters, are run by SPDC as well and the Nembe Creek trunkline. All three of these were essentially financed by Shell and our IOC partners, TOTAL and ENI, where we actually financed the government share. This was essentially a financial agreement a couple of years ago, but is now (chart) through because the projects are on-stream and we are seeing good returns from those. So we're very pleased with that. We were not prepared to go on financing all of the Nigerian share, because you're probably aware of the Petroleum Industry Bill progress in Nigeria which will hopefully move the whole industry to more stable financing. You mentioned the Dow Jones Sustainability Index. And you're also probably aware that we and the industry in particular, we've been looking for some time for good trackers of our performance in sustained government. We had thought that the Dow Jones Sustainability Index might meet these needs. But unfortunately, it would appear that is not the case. We are very disappointed with the outcome of the decision by the Dow Jones Sustainability Index. It is. as you state, based on their assessment of Nigeria. But I have to say, I'm afraid, it's a very non-transparent assessment. They didn't really bother looking at the facts in progress in Nigeria, which I have just talked about actually is relatively positive. We are certainly in all sense of security, spills, flaring, production, community relationship better positioned than we were 12 months ago. And so I'm afraid you'll have to put in questions as to the integrity and quality of the process to the Dow Jones Sustainability Index team themselves. We remain very disappointed by the outcome.

You just introduced this index to your remuneration policy. So what does that mean?

Well, we'll need to say, is obviously a decision for our remuneration committee, which (inaudible) the Board and haven't yet decided. And the actual score, as you are probably aware, and against the properly assessed part of the questionnaire that Dow Jones uses was an improvement on the previous year despite the fact that the industry as a whole fell. So actual underline performance as tracked on an objective basis, improved. $115 million, I think it'll probably be inappropriate of me to comment on the circumstances. Probably more than enough legal actions going on for BP to then comment on that.

Are the legal actions going on?

There are many legal actions going on. I think it's inappropriate for me to comment on whether we participate or not.

The next question comes from Eduard Gismatullin of Bloomberg.

I just wanted to ask you a question about your plans in Eastern Africa. Because I have spoke to companies exploring there, and I heard that you're looking (for much) there. I wonder what is of interest, and whether you plan to basically expand your reach there or secure any fields there.

We have looked at opportunities in Uganda and Tanzania. We are not necessarily taking them forward. We're looking or have looked at exploration opportunities in Mozambique and again in Tanzania as well. And at the moment we are not progressing at great speed there, I think is fair to say. They could be potential, but we haven't finished our assessment.

And is there any timeframe for these assessments because it seems to be getting crowded there?

Well, we are well aware that success boosts the price up and that that creates a window of opportunity potentially before the prospects have been drawn, but I wouldn't like to put a timeframe on that. Our focus at the moment is not so much East Africa. Our exploration activity, very much in the Americas, Gulf of Mexico, Brazil and Alaska; onshore gas both in the Americas and elsewhere in the world, in China and Australia and our historic positions in the South China Sea, Malaysia, Brunei and Australia. So that's our exploration focus. We do have some attractive frontier, like throughout the world in places like Italy, Tunisia, South Africa, (Guan) and Columbia. So we have lots and lots of opportunities, and we see those as more attractive than what we see in East Africa at the moment.

And I just wanted to follow-up on Nigeria, because as per the report that basically put a price tag for your sale of deals there, about $ 4 billion. Do you have any, like internal sort of target where you want to see your sale there?

Good question. I can't really comment on what was press speculation, but we'll have to take that number and see whether it's appropriate. We haven't even confirmed or described the blocks that they were talking about. So it can only be regarded as speculation today.

The next question comes from Daniel O'Sullivan of Energy Intelligence.

You do seem to have quite good a good timing along this, because with regard to the AOSP expansion and Jackpine and the Scotford Upgrader, you were saying you are going to save $3 a barrel on unit costs. So I am wondering, you no longer breakout Oil Sands as you did briefly for a while. Could you give us a figure for when every thing is up and running, kind of all integrated in this first phase expansion in 2011, what the break even cost there for barrels will be? And also what the kind of book profit level for the barrels will be as opposed to the breakeven operating cost?

May not be a direct answer. What we have stated is that once we are up and running at $70 barrel, which is just below where we are today, we'll generate $1 billion of cash from that activity, and that clearly would be profitable. Our breakeven cash, well our cash costs are in the $30 to $40 barrel rate. So that $3 reduction is about 10% and will take us closer to $30 to $40. The actual cash cost does depend a bit on what's the cash price. So it certainly will fall in the below 40 cash breakeven. The earnings breakeven, the current depreciation is of $7, $8 a barrel. So you can add that on for the earnings breakeven. Our economic breakeven, the second expansion, were $70, $75 a barrel. That's the economic lifecycle breakeven. Going forward, our debottlenecking should take the breakeven on that part of the portfolio that the debottlenecking investment should be below $50. And we have already paid back the first investment as we have already had the money back in the first five years through 155,000 barrel a day (sales). So put all together, which is what we look at, this is a pretty successful investment, particularly if we had (inaudible) higher oil prices.

So when you are saying, the economy returned on the second expansion, you mean the expansion you are just completing?

That's correct. So including the Upgrade, they breakeven. Economic price lifecycle was, we've said between $70 and $75.

And by economic, you mean by that including your acceptable IRR base.

That present value IRR based calculation, correct.

The next question comes from (Alex Lola of Reuters).

I had just had a question about business with Iran, which is interesting at the moment. Shell was among a few energy companies in Europe, which the U.S. last month had agreed to abandon their activities with Iran. Firstly, could you say what your projects, if any, this has impacted or will impact? And secondly, is your oil trading with Iran, your purchases of Iranian crude oil, is that business as usual nowadays or has that been affected at all by any sanctions or other measures?

First I'd just like to reiterate, we always have and always will work within sanctions and the legal requirement. We've never done anything with being outside sanctions. All been covered by sanctions. Yes, there was a recent announcement by the State Department that we had agreed that we would cease any activities that would fall within the raiment of the new Iranian sanctions there the (SADA) Sanctions Act that was passed earlier this year in the U.S. Growth would be low in materiality terms. We don't have big investments there. We are withdrawing from some small downstream activities and we have been providing technical advice to some of the upstream. But that will then stop. We stopped actually supplying refined products last year, and we're not supplying aviation fuel outside to Iran. I think it's fair to say then, the European (Index) late September, which was only clarified this week, we still need to understand that there are clearly some implications around payment transactions. Our training business with Iran is carried out under longer term contracts. We continue to lift under those contracts. But we do need to assess any implications of the European legislation, which as I say is pretty much out of the press to understand what any implications may be there. But just to be clear, crude trading is not covered under the (SADA) Act in the U.S. It's not a sanctioned activity.

Thank you.

Okay. I hope that covers everything. Many thanks for the questions. Seem to have been a good run for the global business activities. And I look forward to talking to you again in the Q4 results. We plan to release those on the February 3. Peter will join me for that call, and hopefully we'll have some good results to talk to you about again. Thank you for your questions today and for joining the call.