Shell plc (SHEL) Q3 2012 Earnings Report, Transcript and Summary

Simon Henry - Chief Financial Officer and Executive Director

Martijn Rats - Morgan Stanley, Research Division Jon Rigby - UBS Investment Bank, Research Division Michele della Vigna - Goldman Sachs Group Inc., Research Division Theepan Jothilingam - Nomura Securities Co. Ltd., Research Division Oswald Clint - Sanford C. Bernstein & Co., LLC., Research Division Iain Reid - Jefferies & Company, Inc., Research Division Jason Gammel - Macquarie Research Kim Fustier - Crédit Suisse AG, Research Division Douglas Terreson - ISI Group Inc., Research Division Irene Himona - Societe Generale Cross Asset Research Lucas Herrmann - Deutsche Bank AG, Research Division Alastair Roderick Syme - Citigroup Inc, Research Division Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Peter Hutton - RBC Capital Markets, LLC, Research Division Hootan Yazhari - BofA Merrill Lynch, Research Division Bertrand Hodee - Raymond James Euro Equities Colin Smith - VTB Capital, Research Division

Welcome to the Royal Dutch Shell Q3 Results Announcement Call [Operator Instructions] I would like to introduce our host, Mr. Simon Henry.

Thank you, operator. Good afternoon, good morning, wherever you may be. Welcome to the Royal Dutch Shell Third Quarter 2012 Results Presentation. I'll give you a summary of the performance over the last few months and then take your questions. First of all, particularly for those on the web, the cautionary statement. Shell is pursuing and delivering on a long-term and consistent strategy against a backdrop of very volatile energy markets. Any one quarter's results are simply a snapshot of the delivery against this long-term strategy. Third quarter underlying earnings were $6.6 billion. Earnings per share declined by 6% from the third quarter a year ago. We have announced around $6 billion of asset sales so far this year, part of the overall capital efficiency drive. Our growth projects continue to ramp up well. We've launched a couple of new projects, oil and gas developments in Italy and the United Kingdom. And we've been adding new positions for future growth out towards the back end of the decade. So let me give you more details, and I'll start with the macro environment. If you look at the macro picture here compared with the third quarter of 2011, liquids and gas realizations both declined from a year ago. But within that mix, I'd highlight the discount of WTI to Brent, and the discount of Western Canada Select, or WCS, to Brent. And that, of course, is important for our heavy oil business in Canada. All these discounts remain wide by historical standards, a $17 discount of WTI to Brent, and a $33 discount of WCS to Brent. On the gas side, oil-linked natural gas realizations increased year-over-year, and you can see the uplift in our integrated gas results. However, by contrast, the spot gas prices in North America declined sharply from…

[Operator Instructions] The first question comes from Martijn Rats from Morgan Stanley.

I have 2 questions. First of all, I was hoping you could elaborate a bit on the loss in the Americas. Also, specifically, when you would -- when would you expect to see an improvement there? How structural are these losses? And secondly, I wanted to ask about the refining results, which benefited, of course, from stronger margins. But even compared to the margins, our assessment was that it was a pretty robust result. So I was wondering if there is also another element of improved operating efficiency or something along those lines to that result that could perhaps be a bit more structural.

Yes, Martijn. Clearly, those of you who delve into the detail will notice the loss in the Upstream Americas were around $100 million. And that compares to that $700 million in profit a year ago. Firstly, strategically, the Americas is a very significant growth area for Shell. We have around $50 billion of capital employed there. We're investing something like $12 billion, $13 billion per year in the Upstream business. As we invest, we expected a reduction in profitability as we see 2 things structurally. There are higher upfront depreciation charges partly as we amortize the nonproducing leases, but also partly as we see high depreciation in early production of the onshore. And we also have quite a high level of feasibility and exploration expense as we investigate possibilities for, for example, LNG or GTL projects in the future. So there are 2 structural high levels of spend there. We have also seen, if we go year-on-year, much lower gas prices. We've also got those much lower Canadian oil realizations. So if you look year-on-year, the costs -- these explorations costing around $300 million year-on-year, and the price effect is around $200 million year-on-year. I mentioned the downtime in Hurricane Isaac. That's about a $100-million impact in the quarter. And a variety of the smaller issues. There's no real issue other than the ones I've talked about in terms of cost, and the reliability, deepwater and the oil sands -- of the heavy oil activity has been very good. The final factor and structural this year but positive going forward is we've deliberately slowed down the onshore gas activity. We switched the rigs. It is now actually 29 in liquids and 11 on gas as we take on the Permian activity. That has meant we've invested some $700 million less…

Our next question comes from Jon Rigby from UBS.

Quick questions on the gas on the North American side again, just to return to that. Can you -- are you able to estimate at what point the current portfolio onshore turns positive? And also, the degree to which your volume sensitivity starts to change, i.e., when do you start to raise gas production again? And I guess circling back on to what your existing production is, is what do you think the production is that you've foregone by taking the economic decision not to produce from that portfolio? And then just lastly, can you just remind me, why are you depreciating on a straight line basis on those licenses rather than holding them back to depreciate them on a UOP basis when they come into production?

Thanks, Jon. The onshore turning positive, well, $5 Henry Hub would help. Our sensitivity is $1 Henry Hub is about $100 million per quarter. So that would certainly help. We don't give effectively a bottom line income for our onshore gas on the grounds that the significant allocate-able expense, which confuses the situation. But I will say that the total depreciation is around $3 billion per year at the moment. So when does it turn positive? Difficult to say. When does the potential liquids volume offset the volume loss in gas? Well, Marvin tells me he thinks we catch up by the end of 2014 in volume terms. Of course, at the current gas-oil price arbitrage opportunity, that means the cash generation and the earnings performance probably gets better earlier than the end of 2014. That will depend, of course, on ongoing drilling rates, and that's something that we need to assess ourselves as to at what rate we pursue both. And why do we depreciate? Our general approach to signature bonuses, for example, is to amortize over the life of the lease. So in Alaska, for example, it's being amortized over 10 years. And where we are assigning a purchase price premium on where we've acquired assets, asset premium, we also do amortize some of that over what we see as the early lifetime of the assets. So I would say, we're aggressive in depreciation and conservative therefore in earnings.

Right. And sorry, on the gas production foregone, do you think there's an estimate? Again, it may be what you'd been if we were running it somewhere in the middle of your planning price.

Well, compared to what we might have expected to deliver this year, we're probably about 30,000 short by the back end of the year. But that -- it would have probably attracted -- because it would attract more UOPM depreciation, it would merely have attracted more losses had we done it.

Yes, no, and that's the figure that Marvin's saying you can catch up in liquid terms by end 2014.

In volume terms with -- by -- in a couple of years' time, we should have offset the lower gas production by higher liquids.

Our next question comes from Michele della Vigna from Goldman Sachs.

I had 2 quick questions. The first one is, on the 3 big projects and 450,000 barrels per day of capacity there, do -- should we expect to get full utilization of their capacity, let's say, next year? Or should we assume that your average utilization there is always going to be somewhere below 100% due to maintenance, et cetera? So should we assume something around 90% there? And my second question would be on your dry gas activity in the U.S. and whether there is a specific level of gas price above which you would actually start to ramp up that activity again.

Thanks, Michele. The big projects. Firstly, the 450,000. You wouldn't expect to average 450,000 necessarily in any given year, particularly not the first year. And on the oil sands piece in particular, we are actually working our way for the next year or so through some of the not-quite-as-rich oil base as well. So what we would hope to do is demonstrate we can operate sustainably and reliably, add capacity at all the assets. Already done that, by the way, in LNG and, in practice, in the oil sands in terms of the tonnage of rock moved. And we hope to get the GTL as well. So one step at a time. We would like to get everything up and running, ensure we can keep it there by the end of this year. But I don't think we would run on average at the 450,000 for the full year. As we get more experience, we tend to de-bottleneck. And yes, we would expect to see high production. On the gas price, what price would make it attractive? Well, economic breakeven in West Canada or Marcellus is about $3, but that wouldn't mean that anything above $3, we would ramp up. We essentially look at our total operating capability and the number -- basically, the number of rigs we can operate safely and reliably and decide where we want to apply that. I think it's fair to say the focus will be on opportunities like the Eagle Ford, like the Permian. We will continue to drill the Marcellus and in the Groundbirch in Canada. But that may -- the targeted really is the capacity that we already have in place for aggregation pipelines, et cetera, making sure we fill the capacity. So I think for the next year or so, you will certainly see the focus being on the liquids rich.

Our next question comes from Theepan Jothilingam from Nomura international.

Two quick questions. First is just, I mean, coming back to volumes. Just want to get a sense of whether you -- there was any other sort of significant planned maintenance next year, whether you're in a position to give a more explicit outlook at the group level for 2013. And then secondly, just want to revisit the buyback. Just wanted to understand whether you're still sort of hamstrung in terms of how much you can buy back in the market. Any sort of progress in terms of discussions with the Dutch authorities?

Thanks, Theepan. I don't think we can give a forecast or projection ahead for 2013 just yet. We'll probably do that with the Q4 results. I will say that clearly, very -- quite a few moving parts. We're suffering theft of 50,000 barrels a day in Nigeria direct from trunk lines, and we can't measure how much from everywhere else in the system, plus the sabotage impact. And that remains very material in terms of its impact. The -- what I can say positively is we do have that oil -- the LRS ramp-up to come. We have the ramp-up of the projects that we just talked a bit, the 3 big projects. We have -- hopefully, we'll see Kashagan come onstream. Hopefully, we will get the first commercial production in Iraq. And generally speaking, a fairly robust portfolio. Our decline rate in the quarter was 130,000 barrels a day. It start -- that's shading down a bit over the past couple of years from the 150,000 level, partly because of the introduction of the longer-lived projects. So it's reasonably robust outlook. And remember, of course, that our actual expectation over the next 3 years is a cash flow target, not a production target. So a 100 billion -- $100 barrel should give us $200 billion of cash generation, and that's what we focused on delivering. The barrels will be what they will be. Buyback constraints. Unfortunately, as you're probably aware, there is a new Dutch government. Well, fortunately, there is a new Dutch government. Unfortunately, that means that the changes that we've seen, plus the fact that the government actually fell on budget considerations, there's been no real opportunity to have the discussions around some of the constraints we face, which are essentially fiscal constraints. And therefore, no real move on that. No real discussions. We are, in practice, limited to 25% of the daily trade in RDS B shares on the London market, which works out roughly at $25 million to $30 million maximum per day. And that's what we've been doing when we've been in the market.

Great. Just coming back, I mean, no significant planned turnarounds in any of the large assets for next year. Just announcing -- just want to confirm that.

For next year?

Yes.

There will be some, I imagine. I don't have actually the program in front of me. The planned turnaround in Upstream is typically about 150,000 barrels a day on average. But it does vary quite materially quarter-on-quarter. And I don't have anything in hand to suggest that it's more or less than that next year. Ask me again in February.

Our next question comes from Oswald Clint from Sanford Bernstein. Oswald Clint - Sanford C. Bernstein & Co., LLC., Research Division: Could you just update us on your Gulf of Mexico performance here in terms of where the volumes are heading, impact of adding new rigs into the offshore, et cetera? And then also, secondly, just on -- what are your thoughts on NGL pricing, especially as you talk about these LRS growth platforms? Or what's the NGL impact if it stays depressed on kind of unit margin from that growth?

Thanks, Oswald. The current performance is just under 170,000 barrels a day in terms of Gulf production. We have -- now have 8 rigs operating, 6 deepwater. Some of that activity -- 6 floaters and 2 off the platform. Some of that activity is focused on exploration and therefore has minimal impact in terms of short-term production. Some of it is associated with Perdido and ultimately moving on to Mars B drilling ahead of that project coming onstream in 2014. We are hopefully seeing pretty much the bottom of the production, the decline that we've seen post the moratorium. Turning that around, Perdido is growing well. We will have, in fact, 11 rigs up and running by early next year as we ramp up the activity. We only had 8 pre-Macondo. So we're actually returning to a higher level. Again, by 2014, back end of, we should have sort of brought our Gulf of Mexico production back to where it otherwise would have been if there had been no moratorium. And that's when we should also see the impact of the 2 new projects, Cardamom and Mars B. They are both doing well, both on track. But I can't really say more about the actual production between now and that time -- that -- late 2014. NGL pricing. Clearly, there are volatility in the market at the moment. We are in the process of reversing a pipeline that should help Eagle Ford and Permian production get down to the Gulf rather than going through Cushing, which should help relieve some of the volatility or the bottlenecks. Now that should be up and running earlier next year. We are also, as a chemicals -- major chemicals producer on the Gulf Coast, a beneficiary of low NGL prices, as well as a victim of them as a producer. So in practice, we're reasonably well hedged against the short term from our viewpoint. So I think structurally, there will be logistical dangers that will remove some of those short-term anomalies in the market. But it does help to be a consumer as well as a producer of NGLs. So I wouldn't like to guesstimate the net impact on Shell, but there is something of a hedge in our portfolio overall.

Our next question comes from Iain Reid from Jefferies. Iain Reid - Jefferies & Company, Inc., Research Division: Simon, 2 questions. Just before that, did you say earlier that you're losing 50,000 barrels a day due to theft in Nigeria?

Straight from the trunk, the pipelines, that's 100% SPDC. We're 30% of that. Iain Reid - Jefferies & Company, Inc., Research Division: Okay. But on an industrial scale is there...

It's about 150,000 a day in total, we believe. And that -- the 50,000 is only what we can measure down the trunk lines. The 150,000 is across the whole industry as well. In fact, it is just impossible to measure. And so I think "industrial scale" is an accurate description. The finance minister in the country has made the -- drawn the obvious conclusion. That's $5 billion to $7 billion a year of theft. Iain Reid - Jefferies & Company, Inc., Research Division: Amazing. Anyway, look, I had 2 quick questions. Firstly, you talked about the ramp-up of the big 3 projects. Is it possible to say what sort of cash flow per quarter or per annum we can expect from that at, say, current oil prices, $100? And secondly, on your write-downs in the U.S., I was surprised that you didn't impair your Western Canada assets given the fact you paid quite a lot of money for them when gas prices were significantly higher. Was there a reason for that? Are you assuming LNG export pricing in the future? Did that offset the negatives on domestic pricing?

Well, thanks, Iain. First, the 3 big projects. Typically, quarterly, they've been doing just over $1 billion of cash flow per quarter, and earnings were just under $1 billion. So the aggregate cash flow in 9 months is about $4 billion from the 3 projects. So that's great, great growth. And obviously, there's more to come there. And that is obviously at current oil prices. Impairing West Canada assets. Impairments, I mentioned $4, are a function of 2 things: how much you paid for the assets in the first place; and how good the assets are; and I guess, also the cost of your own development and operational costs. Neither in West Canada more Marcellus, where we acquired big positions, are we in danger of impairment. No, it's not assuming LNG prices. We would not be able to do that. And of course, the -- we look at cash generating units. And in both cases, not only did we make the large headline acquisitions, but we picked up significant amounts of acreage at much lower price. The resources in the Groundbirch play alone have doubled relative to the original Duvernay acquisition. We're at 12 tcf now relative to the 6 tcf at the original acquisition. So the quality of the assets, the fact that we're producing at low cost, low development cost, great drilling performance, great efficiencies is the reason for no impairment, even carrying the premium that we paid on the acquisition. So it's good quality assets, low cost of production.

Our next question comes from Jason Gammel from Macquarie.

Simon, I wanted to ask a question on the LNG business and future strategy. You've done quite a bit this year to increase the optionality that you have in future LNG supply between what you've done in Canada and Australia and then potentially signing on for U.S. offtake in the future. Can you talk about -- and I realize that getting optionality gives you the option-making decisions in the future -- but where each of those would rank in your current development queue? And then secondly, how this would affect your appetite for obtaining equity in Mozambique.

Thank you very much, Jason. Good questions. Very important strategy -- strategic area. Just refer back to the $2.6 billion in the quarter. Integrated gas is not only an area of future growth and value; it is an area driving today's results. The future strategy, we're working or we're building 7 million tonnes of further capacity on top of the 21 million that we currently participate in. That's basically all in Australia. And we are investigating over 15 million tonnes of potential additional capacity, some of which is in Australia and, as you point out, Canada, Indonesia and potentially in the United States on the Gulf Coast or a part of that. Difficult to say how they individually rank. Clearly, floating LNG, we're currently constructing in Korea for Australia, looks good, particularly if we could take the costs down the learning curve as we build and learn from the first -- the #1 license plate. So the Indonesia project, although that's operated by Inpex initially, that will be floating, and so we'll transfer some of the experience there. So we'll see how that looks. Australia, we have the Arrow project, Browse and Sunrise on the to-do list. The onshore developments in Australia currently do suffer some inflation, as I'm sure you're aware. Canada, we are putting together the full value chain from the molecules through to the market with our 3 Asian partners. We need to secure the pipeline, the LNG opportunity, and put the permits together. That's -- so it's going to take some time to put all of those different elements together. But with the low cost of gas supply and the very abundant gas and the very solid partnerships, Canada looks reasonable as well. Gulf Coast depends almost entirely on, what price could you access capacity and then ensure that you get the permit? So I can't give you a ranking, but they're all currently in progress. What does that do for Mozambique? Well, Mozambique is clearly a big play, maybe a very big play. But big plays come with big price tags and significant operational challenges. We bid for Cove at a price we were comfortable with. We pulled out because we felt the process would take us to a price we're not comfortable with. And, I mean, you're talking potentially $150 billion or more of investment in that country with -- given the gas resource, and it's not something that you pay a lot upfront or too much upfront to get involved in if you've got that kind of follow-on challenge, together with the clearly developing infrastructure with ports, roads, railways and domestic capacity, capability and consumption. So it looks like a good resource, but we're not going to overpay to enter it.

Our next question comes from Kim Fustier from Credit Suisse. Kim Fustier - Crédit Suisse AG, Research Division: Just 2 questions, if I may. Firstly on your portfolio strategy, going back to North American gas, you've talked about trying to match acquisitions and disposals broadly by geography or asset type. So I can see you've spent $2 billion this quarter buying acreage in the Permian. You've added many other positions in the last 12 months. But I have not really seen any specific announcements on asset disposals recently in North America. So I was wondering whether you're still very much in acquisition mode, still making net additions to the North American portfolio, and if so, when you'll start selling positions to effectively high-grade the portfolio. My second question is on Iraq. There has been some noise recently around Shell not being able to meet its production target at Majnoon by the end of this year, and I was hoping you could clarify this point and perhaps, more generally, share your thoughts on the key challenges in Iraq, such as infrastructure, export capacity and security.

Thanks, Kim. Good point on Iraq. North American gas, typically, what we said before was when Marvin wanted to buy something, we requested he sell something to pay for it. That wasn't necessarily a strategic move to always match geography, the divestments and the acquisitions. Right now, it's a buyer's market for gas, maybe a buyer's market for LRS as well in the right basins on the grounds that many of the players holding acreage have a bit of a cash flow challenge. We -- therefore, we're not necessarily a seller either into a soft market. What we are in -- we're focusing the gas assets in Western Canada and Marcellus. We are in the Haynesville and Pinedale, clearly, from the impairments, the less attractive basins. But probably that means it's not the right time to be selling. We did sell Holstein, of course, offshore for a nice price this quarter, but that is -- colloquially, is a deepwater activity. So at the moment, we are -- we're just looking for the assets that are at the right price in the right basin with the right potential development cost. We're actually in a double-digit number of potential liquid basins across North America. Some of these, we will not develop either because we don't see the potential or because somebody -- it fit somebody else's portfolio better. And that's why we're doing the exploration and appraisal now. And it's looking good in Eagle Ford, in the Permian, the Utica and the West Canadian basins, the Mississippi Lime. One or 2 of the others may be not quite so attractive. So we'll work that portfolio out over time. Iraq, we are in 3 activities in Iraq. In the sense of the general question about developing there, all 3 fall in the same…

Our next question comes from Doug Terreson from ISI.

My question is on the Downstream and specifically, your commentary suggests that the intermediate-term outlook for global refining may be challenged. And on this point, I had a couple of questions. First, given your global perspective, I wanted to see if you could provide more color on some of the global demand trends that you highlighted and that Shell is seeing globally. And then second, on Shell specifically, while the Downstream was strong this quarter, the returns on capital have really not improved this year as has been the case with some of your peers. And so I wanted to see if you could provide an update on the scale and scope of some of the return enhancements that are underway in the Downstream at the company.

Thanks, Doug. Long time, no speak. It's good to hear we've got U.S. listeners on the call. I hope that you're all managing to get through some of the problems of the recent hurricane. The global refining, we still see it as challenged. It's 7 million barrels a day of excess capacity, and it will probably rise to 8 million or even 9 million over the next couple of years depending on how demand progresses. We see demand for crude oil. It's up maybe by 0.5 million barrels this year, maybe less, against what was a 1 billion to 2 billion barrels a day growth trajectory on which the basis of new refineries was, I think, the investment case. And we see some mismatches in product slate as well, with much higher demand for diesel and gasoline in quite a few parts of the world. Now Europe is chronically oversupplied and while in the short term, the occasional bankruptcy or maintenance turnaround helps margins, it's not going to get any easier. The U.S. is benefiting, obviously, at the moment, from both shutdowns in the U.S. and elsewhere, for example Venezuela, but also this WTI disconnect from Brent. How long will that last? Well, we don't see demand that strong, particularly on retail at the moment. Overall, always difficult to read the trend. The U.S., industrially and commercially, seems to be in a better place than Europe. What we don't know is how sustainable that may be. Perhaps we'll wait until after the election. The emerging markets, doing well, still growing, a bit of a interregnum in China in the past 6 months, but may -- that may well come back. But of course, refineries are being built. So there are still new refineries, many new refineries coming on the Middle…

Our next question comes from Irene Himona from Societe Generale.

I had a couple of questions, please. So firstly, in oil products, is it possible to say how much came from Brazil from the Raízen JV this quarter and, perhaps, what the comparable was last year? And then secondly, if you can give us an update, please, on plans for Arctic drilling, I suppose, in the next season now.

Thanks, Irene. The JV, Raízen, doing well, definitely learning to squeeze more out and expand on the capacity that we have. It's around a $100-million contribution, slightly better than last year. It's also got, obviously, the Downstream contribution, the marketing contribution, as well as the ethanol. But so far, very successful collaboration, very well placed despite what is actually a difficult ethanol market, a bit distorted by some gasoline subsidies in country. Arctic drilling, just to -- and that's a very important question. Just to go back to the context, our exploration plan, which is multiyear and always was several years, 5 exploration wells across Chukchi and Beaufort seas. We planned originally to drill 2 of them this year, one in each, and we aim to have the facilities or the capability of those 2 rigs, plus over 20 support vessels, in place. We did achieve that, barring 1 vessel. The vessel that was missing was the containment barge, which is the fourth barrier against a potential blowout and spill incident. A lot of our effort has been projected or targeted at avoiding a blowout in the first place. But in the event, very unlikely, that, that were to happen, the drilling mud, the blowout preventers, drill shear rams, the capping stack would all come into operation, all fully tested, before we would need the containment barge. However, the absence of the containment barge meant that this year we were only able to drill 2 top holes, and I think I mentioned down both to 1,400 feet. We've pulled off there, both of them, as of yesterday and the fleet is moving south, I think it's fair to say now, for the winter. We intend, obviously, next year to go back to those 2 wells. We would hope to be able to complete the holes into the reservoir. I cannot say any more than that, that we would plan -- the 5-well exploration plan remains valid. It is valid for several years. Obviously, well 3 and 4 will depend a little bit on the results of wells 1 and 2. But we are, we believe, very well placed. Very positive outcome this year in terms of the regulatory environment, which we now think there's much more clarity on so that we can go forward with more certainty next year. Good, constructive discussions with regulators both at the federal and the state level. And we look forward to a positive outcome in 2013. Hopefully, that covers the Arctic. And thank you for the question.

Our next question comes from Lucas Herrmann of Deutsche Bank.

2 or 3, if I may. I wondered if you might talk a little bit more about the build-out of your tight oil positions. Clearly, a lot of capital is going in. What one can't see or there's little transparency on at the moment is the extent to which production has built and is expected to build over the medium term. What are objectives? Secondly, just on the downstream, your fourth quarter, historically or certainly the last 3 years, has been somewhat astray from the performance through the previous 3. Are there reasons why we should expect a better performance in the fourth quarter of this year relative to the past? And thirdly, I just wondered if you could comment at all on what's happening with GTL, V-Power, the extent which you're finding you're able to expand the market and consequently cement the value from that product?

Thanks, Lucas. I'll try and be quick on this. The LRS positions, we'll have invested about $1 billion in development this year, including building facilities in Eagle Ford. We should have -- I mentioned one facility coming online. There's a second facility in the near future. We, therefore, have around 40,000 barrel a day in Eagle Ford capacity, and we're doing the drilling to start to fill it. We'll be around about 20-or-so by the end of the year there, added to the Permian and a couple of other basins, that backs the 50,000-barrel-a-day exit rate in North America. We now have -- we picked up 7 rigs in the Permian, so we've now got 29 operating on LRS positions, of which the practice [ph] just over half are on development and the other half are on still exploration and appraisal activity. We're still aiming to answer your question, I think, is the short answer as to what is the appropriate level of development next year. Certainly, as we take on new acreage, particularly if it's coming off directly from others, we need to ensure that we're moving to our own standards on safety and operations. And sometimes that puts a slight slowdown on before we can ramp up, but let's see. We start the year at 50,000. Let's hope we can end the year considerably higher. Fourth quarter Downstream, apologies to confirm that you have been right on that over the past couple of years.

No, it's obviously wrong, Simon. That's the problem, but...

There are no reasons that I'm aware of why the fourth quarter should be particularly difficult this year. We have had good operational performance. We do have some shutdown activity planned in Europe, but that's not necessarily a big hit. I think the one thing we do see in Q4 is it's usually a less volatile trading environment, therefore, less likely to make money. I suspect that's because most traders spend the quarter doing things other than trading because they all think they've met their bonus for the year. But that is just a personal insight, so it's a flat quarter to trading rather than a particularly attractive one normally. The demand we see is weak everywhere in our major markets. All OECD markets are down. But your third question does point to some mitigation for Shell. Our market share in almost every large market we look at has gone up. Our unit margins are sustained by the V-Power diesel, whether or not it's based on GTL. I would say we're still not fully ramped up in terms of total premium for the GTL product. But we are making steady progress against the plans we expected, including clean diesel, including base oils for lubricants and including more specialized chemical products. Our -- we are also growing, of course, in areas like the U.K. We acquired sites last year. We're growing in Brazilian retail, obviously, I mentioned earlier. China, we expect to have our 1,000th site -- Shell-branded site shortly. And so we are actually still growing in the marketing, and there's no obvious reason why the fourth quarter should be particularly worse than we've seen in the second and third quarters. However, I'll reserve judgment until February.

Okay. Simon, one other -- by the way, your license to export oil from the U.S., can you comment on that at all, intent, hope, et cetera?

Not really. It's just putting in place the option to the extent we need to do it. There's -- clearly, there is a lot of product export from the U.S. at the moment, and there are some mismatches between crude supplies, refining geographical locations. And in practice, we're taking optional positions that we will move product around as of when it's most efficient and effective to do so.

Our next question comes from Alastair Syme from Citi.

Can I come back to your comments on the sensitivities? You talked about the $10-a-barrel move at the beginning. Is that some sort of reminder around the $200-billion cash flow framework? I just wanted to clarify that, sort of what sort of assumptions are built into that framework on those spreads, et cetera, you talk about in the U.S. And I wonder, secondly, if you could just talk about what level of capital employed was exposed on the write-downs you took in the U.S. In other words, how much capital is remaining in the Pinedale and Haynesville?

Thanks, Alastair. The comment on sensitivities was more about this year than the next 4 to be honest. It's -- effectively, what I was saying is that the headline Brent price sensitivity is obviously upwards. But about half of it is being offset by the refining and gas prices that we see. If you look at the full year 2012, '15 period and the half that disappears will be less because we've got effectively lower expectations in for, for example, European gas prices. But the full year cash flow generation is based on a $5 gas. Now that is one impact and we'll see where European price is going. We probably don't expect refinery margins where they have been for the last 3 months, but we would expect them better than they were for the previous 3, 4 years, on average over the 4 years. So the comment was mainly about the 2012 performance. Capital exposed, relatively low. There's still some capital on the balance sheet. But the majority of the -- we talked about putting $17 billion into acquiring positions in North America in the past. We've also, obviously, invested at quite a heavy level, but we're also depreciating relatively heavy levels. The majority of the investment has, in fact, been in western Canada and Pennsylvania. So I can't give you a figure. I don't actually have one. But it's not a -- it wasn't a huge amount that was exposed, and there is a remaining balance. We've not written it all off.

Can I just come back to the first about the target framework? What are you assuming on those forward forecasts in terms of WTI, Brent and Western Canadian crude?

A reversion back more to the mean. It's not, today, $17 to $20. But certainly, the first couple of years, we would expect there to be some discount. We do think that there will be logistical solutions. Remember, historically WTI trades at a premium to Brent, not at a discount, so it will move in that direction. But I wouldn't want to get into too many moving parts. What we actually deliver in the environment we find ourselves in will be the most important thing.

Our next question comes from Robert Kessler from Tudor, Pickering, Holt. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Your pessimistic view of refining, expressed in no uncertain terms several times today, doesn't exactly present a bullish picture for near-term refining capacity expansions on the Gulf Coast. So it kind of makes me wonder whether you budget any income contribution at all from the Port Arthur expansion or whether the expansion will bring down the market net to Shell more than the market share increase would benefit Shell. Thoughts on your budget for income contribution there.

Thank you, Robert. I need to be careful about not being too unequivocal, I suspect. The refinery pessimism is global and general. The winners can only be large, complex refineries in the right geographical locations, able to process the flexible crude slate and access markets with a level of certainty. And Port Arthur and most of our other refining assets meet that criteria. It is advantaged in terms of the heavy crudes that can be processed. It is advantaged in terms of its geographical location, either to trade into a very significant U.S. marketing or for further export back into South American, Latin American markets. So we would expect a positive contribution from Motiva overall, not just from Port Arthur, as we go forward. It's big but I'm not sure big enough to move the market in and of itself. But even if it does, the net benefit to us, because we've got the better kick, should be positive. That's the best I can say. Robert A. Kessler - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Yes. Another quick one for me. On gas trading, you cite it as a positive variance in the quarter. Can you quantify that year-on-year and sequentially?

Not really. It's not a figure we give out separately. It's difficult to separate it from the underlying LNG. But it's one of a series of factors. The biggest factor year-on-year really is the GTL and the integrated gas, plus the overall LNG volume uptick, which is partly Pluto coming onstream, partly better utilization, for example, at Sakhalin.

Our next question comes from Peter Hutton from ARBC (sic) [RBC] Capital Markets.

It's Peter Hutton from RBC. Can you just talk about the integrated gas business, its record profits this quarter. You mentioned that volumes were up 4%. But could you just sort of give a little bit of background on the sort of near-term and medium-term outlook, maybe a year out? Given the comments that you're making on the caution in the refining and the Downstream and which is sort of generally industry-related, any implications there on LNG? Are we still seeing that as a very robust market in the near term? And the second one is more of the big picture stuff in terms of the financial framework and the dividend policy. I think you were saying before that you had a look at the dividend when you'd had sort of 6 solid months running of the new projects, and with Pearl up and coming next quarter and Port Arthur not far away, how close are we now from the clock starting to tick? And when does that translate into the timing of when that dividend review would really get into action?

Many thanks, Peter. Integrated gas, we're up 4% in volumes. We see a very tight market for the next 4 to 5 years through 2016, '17 before major new production comes onstream. Thereafter, a lot of the new production is actually already spoken for in terms of re-gas capacity, whether it be China, Japan, India or elsewhere. Even for most of the rest of the decade, it's a reasonably balanced market after the tightness is relaxed a little. Spot market, very robust at the moment. And our challenge, if anything, is ensuring we have enough supply to meet that obvious market demand. We will have an investor day in London on the 14th of November and on the 15th in New York, where we'll talk in quite a bit more detail and context of the gas demand framework, particularly in Asia Pacific, on which we have promising strategies. So hopefully, you will all be able to follow us in that event or those events, one or the other. Dividend policy, the policy is, of course, to grow in line with earnings and cash flow through cycle, sustainably. That's what our investors tell us they like, and to do that in measured, affordable steps. We increased the dividend back in February for the first time in 3 years, as we were able to demonstrate the cash flow growth. We've now -- as you rightly point out, we're seeing further quarters of underlying cash flow growth of $36 billion in 9 months. Just remember, back in 2009 when we froze the dividend, our baseline for cash flow was $24 billion. So in 9 months, we're 50% higher than we were only 3 years ago, and I know there's an oil-and-gas-price effect in there, but there is substantive underlying growth in the cash flow. We won't be jumping into quarterly or unexpected dividend announcements. We, of course, will need to be looking at this as we go into next year because by then, hopefully, we will have seen the underlying, sustainable performance from the big projects. So my own logic takes me to having to consider a dividend increase next year. But we're seeing good progress on the underlying metrics that would make that affordable and in line with the strategy and the policy.

Our next question comes from Hootan Yazhari from Bank of America.

Simon, just a quick question regarding your realizations in the U.S. and the North American onshore business. You've alluded to weakness in price realizations, capacities ramping up throughout the country. I just wanted to think how much the downstream side is now factoring into your future plans, not just obviously refining, but things like expanding chemicals capacity, expanding GTL capacity, cracker capacity, et cetera, to be able to really benefit from the massive amounts of CapEx you're putting in the Upstream to grow the onshore business in the U.S.

Good question. In the short term, the main Downstream investment is actually in LNG into transport. So we're looking -- we're already investing in Canada and looking at the U.S., both with travel centers in, say, the trucking market, but also shipping markets in the Great Lakes and on the Gulf Coast. The -- we will -- or I should say, we are looking at almost all the opportunities you just suggested, gas to chemicals, particularly in Pennsylvania area. We are looking at ethane supply, and some of this is not just the chemicals. It requires aggregation of supply and the treatment there. So there's some strategic control points we need to consider, where they might be and whether we can make the overall value chain work into an area where we do see something of a resurgence of the chemicals and manufacturing industry. It is possible on the basis of relatively low-cost feedstock and energy. The gas to liquids, we are -- I think it's known, we are looking at opportunities on the Gulf Coast. It will take some time to run those through feasibility, design, and we're several years away from any investment decision. But at this point in time, both the chemicals and the gas to liquids look feasible. And you're right that in the long term, structurally, there is a value opportunity there for companies that can go through the full value chain and actually turn gas molecules into either liquids or chemicals price exposure. That's what we're looking to do. It will be, as I say, in both cases, probably several years before we can get to an investment decision. And significant capital will be involved, so we may need to look at some phasing of the investment as well. But overall, it actually looks quite attractive at the moment for a long-term investment. So thank you for the question.

Our next question comes from Bertrand Hodee from Raymond James.

One follow-up in Australia. Along your very big list of projects under study, Arrow, Browse, Sunrise, Pluto 2 or even Gorgon expansion, when do you think you will get a new FID? And on which projects you think is the closest to FID? And when do you think this could happen, 2013, 2014? Can you give us an update on those projects, on their status?

Unfortunately, I can give you an update on the status, but I can't answer the question as to when we expect the new FID. We're not actually the operator in several of those areas, so for Browse or Gorgon, Train 4, we're not the operator. So the ones that we are operator, Arrow essentially is the prime one. We are already in FEED, but Australia overall is subject to cost inflation. You will only make money in LNG if you get your capital cost in the right place and have access to premium markets. While we know we can get into the markets, we need to make sure that the costs are in the right place. And in addition to the ones that you raised, we are also in the Indonesia, in the Abadi floating LNG, which could have certainly attractive potential, and the Sakhalin project expansion to a third train there would also look to be attractive. So we're balancing all of these, and then maybe we don't want to max out on any one country exposure as well. So it's important that we don't rush ahead of ourselves just to meet any notional targets. So I can't give you a date for any investment decisions.

Our next question comes from Colin Smith from VTB Capital.

Can we go back to Nigeria? You've obviously warned about problems with production in the fourth quarter. But your numbers have held up pretty robustly through the course of the year. And I just wondered if you could give us a view as to whether the problems you're seeing now are just a blip or whether they're a presage [ph] of something a bit more serious. And could you also comment on where you think things are with the PIB and how you are thinking about further investments in Nigeria?

Thanks, Colin. Good question, not an easy one to answer. At the moment, the issue is more floods, which essentially is more of a humanitarian issue than the long-term sabotage. So hopefully, we'll be able to get back running there now. The theft -- the industrial scale of theft and the associated spillage is structural, endemic, and there is a limit to what a commercial energy company can do in these circumstances. Production is holding up well there, primarily because of gas. We are effectively a major gas producer and a lot of it's going into NLNG. It's more difficult to steal gas, of course. Our offshore activity remains operating well, but we've not taken any sort of major investment decisions there. We're just trying to keep the facilities full, with the main reason being the PIB being in progress. Now it has been in progress since 2008, so we need to bottlecap [ph] any comments in that context. The government and the president are currently very committed to release. It's our view, and we've made this public, that the bill, the latest draft that we've seen, although it does change on quite a regular basis, is that offshore and onshore gas development would be severely compromised by the bill. It just would not be economic. Offshore oil looks, because it's already taxed at 85%, anyway, is probably less impacted. But the onshore gas development and the anything offshore looks very challenged. So we would hope that there will be perhaps a more pragmatic outcome. And I think not just Shell but the whole industry has been delaying or deferring investment decisions, waiting for a bit more certainty. But it is, as you're probably aware, having followed us for the few years, Colin, that we always talk about we're not…

This concludes the Royal Dutch Shell Q3 Results Announcement Call. Thank you for participating. You may now disconnect.