Status Update

Oct 2, 2018

Slides

Thank you very much, operator. Good morning, good afternoon, ladies and gentlemen. This is Martin Bedczar dialing in from Vancouver, Canada wishing you a warm welcome to the Shell webcast on the LNG Canada final investment decision. I'm joined today by Jessica Yu, our RDS CFO in The Hague and here in Vancouver by Claire Harris, who is the Executive Vice President for Venture Development and Accountable for LNG Canada in my team. Before we start, let me highlight the disclaimer. Now on to business. To date Shell and our 4 joint venture partners have given the green light to LNG Canada by taking the final investment decision. This is a great moment for all of us. We could not have achieved this without the dedication of the LNG Canada team, our joint venture partners and the excellent support provided by the governments of Canada and British Columbia, the town of Kitimat, the First Nations and many others. Construction on the 2 train project will start immediately and we are expecting to start producing LNG before the middle of the next decade. LNG Canada is a great opportunity for Shell, connecting abundant low cost gas in North America to premium demand in Asia at a competitive cost of supply. It fits our strategy and I will go into all the reasons why. We've taken a very disciplined approach in our evaluation to invest in Energy Canada. The internal rate of return of the integrated project is around 13%. And the plant and the infrastructure have been designed and will be built to allow for a possible expansion with a 3rd and 4th train, which if we would take the decision would further bolster the economics of the project. The project has a strong and resilient cash flow profile that is consistent with our ambition to become a world class investment case. It also supports Shell towards another of its strategic ambitions, which is to thrive through the global energy transition to a lower carbon energy system. LNG Canada is very well placed through its low CO2 footprint and will further assist Asia to transition away from coal, which is one of the most carbon intensive of energy sources. I have visited Canada many times over the last few years and every time I've been impressed by the support we receive from all sides. That holds true for the people living in the town of Kitimat, the representatives of the First Nations and the governments of Canada and British Columbia. It also holds true for our joint venture partners who provide deep industry and market knowledge. This makes me confident that together we will make this project a success. Today, we want to give you insight into why we believe LNG Carrera is the right project in the right place at the right time. After this short presentation, I will be very happy to answer your questions together with Jessica and Claire. Let me start with the customer. I always like to start with the demand side. According to our LNG outlook, LNG demand growth will remain strong. It will be driven by GDP growth globally, urbanization and government policies aiming for cleaner air and reduced CO2 emissions. The global energy market has continued to defy expectations of many market observers with demand growing by 25,000,000 tonnes over last 4 quarters, almost 9% growth year on year. According to the Shell outlook, total LNG demand is expected to double by 2,735, with Asia in particular continuing to show strong growth. In addition, declining domestic gas production will further add to the need for additional LNG supply. However, new FIDs have been lagging. Changing market structures have made it more difficult for LNG projects to take FID. And although a number of projects is proposed, they are unlikely to all go ahead at their proposed timing. As a result, the supply gap is expected to open up in the first half of the next decade and LNG Canada is well placed to be a competitive new supply source to fill the demand. Shell has a global portfolio that is unlike any other in the world. Over the last 4 quarters, we sold some 71,000,000 tonnes of LNG, of which 34,000,000 tonnes was our own equity production. LNG Canada adds a new differentiated supply point to this portfolio and is highly complementary to the global picture. The 5.6 1,000,000 tonne of Shell equity volumes produced by LNG Canada will be managed as part of Shell's global LNG portfolio and add significant trading optionality. With all of the LNG demand growth coming out of Asia, LNG Canada is well placed to satisfy the demand. LNG from Canada will be able to reach Tokyo Bay in less than half the time of our cargo that comes from the Gulf of Mexico. It only takes 10 days compared to the 24 days it takes from the U. S. Gulf Coast. And Energy from Canada will not have to navigate the Panama Canal on the way. Another distinct advantage of Energy Canada is the access to abundant low cost natural gas produced from Western Canada, specifically the Montney Basin. The total Western Canada gas resource has an estimated 300 Tcf at a cost below $3 per MMBtu. Shell itself has significant amounts of equity gas through our existing position in Groundworks. Our working interest in Ground Birds is assessed to hold over 90 CF of recoverable resources and has additional potential through continued maturation. And Groundbridge is one of the most competitive producers of gas in the basin with a cost of supply of around $2 per MMB to you and we have seen the cost of that gas continue to come down. The AECO market also provides us with the option to buy gas if this turns out to be cheaper than developing our own. Currently, gas sold in the AECO market is cheap because there is more supply than the local market can handle and exports to the U. S. Are going down. We expect that Canadian gas will remain relatively stranded, certainly more so than Henry Hub gas. Now let's have a look at the site in Kitimat. We identified this location at the time from a list of 500 potential sites in British Columbia as the ideal location for a large scale LNG export facility. It might be a surprise to some of you that a lot of the infrastructure that is needed for the project is already there. So even though you might look at this project as a greenfield development, it already has an existing ice report, roads, railway and power supply. And the town of Kitimat also has an existing nearby airport. The site is also large enough to accommodate at least 4 LNG trains, creating the option to expand the project at some point in the future. And as part of the pre FID preparations, a lot of the site preparation has already been done, which means the site is in excellent shape and will form a solid foundation for this project. Now as I mentioned at the start, LNG Canada has several big advantages, but the absolute cost and the risk of a possible cost overrun had to be dealt with before the project could move ahead. When the joint venture participants decided to delay the FID in 2016, the Energy Canada team took that as an opportunity to work with our partners and suppliers to further improve the competitiveness of this project. In the time Energy Canada retendered and selected JGC Fluor as the EPC contractor on a lump sum basis. The cost to construct the energy plant based on that lump sum contract is expected to be $1,000 a ton. The improvement of the fiscal framework provided by the governments of Canada and British Columbia also helped to ensure the project could go ahead. In addition to improving competitiveness, LNG Canada was also able to lower the risks that come with any major project. Working closely with our contractors, LNG Canada has been able to use proven industry technology allowing modules to be fabricated in Asian yards with a good track record in terms of safety, quality and cost. And the absence of any other large construction project in Canada at this point in time helps to further mitigate the risk of the cost inflation that we have seen before in the industry and in Canada. The construction of the 6 70 kilometer Coastal GasLink pipeline from the LNG plant to Shells Ground Birchfield will be done by TransCanada who will be the owner and operator of the pipeline. That pipeline has been fully permitted and has received the support from all elected First Nations that will be impacted. The schedule of the pipeline construction has been optimized to minimize the risk of coming onto the critical path of the overall project schedule. So now having worked hard to make the project as good as it can be, we are confident that we can ship the first LNG before the middle of the decade with predictable construction costs. At this point, I would like to hand over to Jessica. In the Hague? Thank you, Martin, and good morning and good afternoon, everyone. Shell's strategic ambition to become a world class investment case means that the project has been subject to our disciplined approach to capital investment. LNG Canada was critically reviewed for affordability, competitiveness and returns. The funding of our share of the project fits within our existing range for capital investment of $25,000,000,000 to $30,000,000,000 per year, and it is consistent with our organic free cash flow outlook. This means the project is affordable. The project competes with greenfield projects on the coast of the Gulf of Mexico for LNG supply into Asia. We consider these to set the marginal cost of supply for LNG in the future. When compared against a typical greenfield development on the Gulf Coast, we expect LNG Canada to benefit on average from lower shipping costs of around $1 per MMBtu. In terms of the gas supply, including the cost of the pipeline, we expect to see on average a $0.50 per MMBtu advantage. In combination, we see a $1.50 per MMBtu advantage that adds to the competitiveness of this project. When we look at the total delivered cost into Asia, we expect to keep roughly half of this advantage. In addition, the low marginal cost of supply from LNG Canada means that the project is expected to remain cash flow positive even during challenging market conditions and then returns. The integrated project is expected to deliver an IRR of around 13% and this is at a gas price of $8.50 per MMBtu real terms 2018 delivered into Tokyo Bay. And there is still significant upside if we together with our other joint venture partners would decide to proceed Train 34. The project not only competes well on the cost of LNG delivered, but it also has been designed to achieve the lowest carbon intensity of any large LNG plant in operation today. This is a result of tight control on emissions in the upstream, the composition of natural gas in the Montney and the use of hydropower. As you are probably aware, Shell has signed up to the methane guiding principles that aim to reduce the emission of methane through higher standards. This project will comply with those principles. And let us not forget that the LNG supply by this project can help to improve air quality in Asia by replacing more polluting coal. Natural gas produces less than a tenth of the particulate matter compared to coal when used to generate power. This means this project is contributing to a cleaner environment and will be well placed in the energy transition to a lower carbon energy system. I imagine you would like to ask some questions, so let me wrap up. I believe that LNG Canada is the right project in the right place at the right time. It is the right project because it delivers more and cleaner energy in the form of LNG and does this in a very responsible and competitive way. It is in the right place because of the access to abundant and low cost natural gas, the short shipping distance to North Asia and the support from local communities, First Nations and the government. And it's the right time because the project has had ample time to prepare, derisk and make the project as good as it can be to deliver the first LNG when the market will need it. This all means I am convinced we will make this project a success. Thank you for listening. Martin, Claire and I will now take your questions. Thank you first question is coming from Oswald Clint. Please go ahead. Your line is open. Thank you very much, Martin, Jessica and Claire. I just want to I mean, obviously, there's a lot of data in the press release. I don't remember another LNG project from Shell with so many data points, so you've made it easy. But it is a little bit vague on the startup of the project, middle of next decade With all of the pre planning you've done, I wonder if you could be a little bit more specific or talk about just how conservative you are in terms of that middle of the decade start up on this project? And then just linked to that, I was curious about the 7,000,000 tonnes per annum of each train capacity. Is that already because obviously that's an increase from the 6 and the 6.5. Is that including some debottlenecking expectations already? Or is there a chance you could debottleneck these 2 plants with time? Thank you, Oswald. Yes, the start up literally is indeed before the middle of the next decade as we expect it to be. Clearly that schedule holds contingencies. It is not the fastest way you could ever build a project. But of course, we've never realized the fastest way. There are always unexpected turns in a project of this size and complexity. But our expected date including these contingencies is before the middle of the next decade. And together with our contractors, we will make sure that appropriate schedule pressure is applied, but quality and safety come first. The 7 MTPA is the design throughput of the trains that we will build. It is indeed our so that doesn't include debottlenecking although of course design is as debottlenecked as we can get it. But it is our experience in starting up and operating LNG plants around the world that we always once it is on stream, we find new ways to remove bottlenecks and to re rate and eventually debottleneck the plant. So if history is any good guide, we would expect to get more than 7,000,000 tonnes out of these trains over time. But the design capacity and the base for the economics is 7% that we are now confident of. Understood. Thank you very much. And thank you much, sir. We'll now go to our next question coming today from Christopher Kuplent. Please go ahead. Thank you very much. Thanks for taking my question. Martin, I just wondered whether you could paint a little bit of a broader picture for us, how this project you think competes against other LNG projects that could receive FID, both within the Royal Dutch Shell portfolio as well as without? What are your hopes regarding progress in Qatar? So I just wonder how you got to this stage and whether this FID rules out immediate positive final investment decisions from Shell also on Lake Charles, for example, I. E. The second question would be a little bit of a timing outlook as far as your options within your own portfolio are concerned? Thank you. Thank you, Christopher. Let me start with the second question and then work my way back to the first. With Prelude coming on stream before the end of the year, essentially the integrated cash portfolio will have brought all its major projects on stream. And that means that within our capital outlook, we have space certainly for Energy Canada, But we probably have space for another project if the right project reaches the majority with the right level of competitiveness. So this does not rule out other FIDs in our portfolio, but we will be as disciplined as we've been on Energy Canada to get them to a place where they are as good as they can be and competitive with industry options before we would take a second one. But in principle, the space in our capital allocation is not a constraining factor. We really just need to make sure that we have top quality projects to take decisions on such as this one. The broader picture within our portfolio, the other relatively prompt opportunity is indeed Lake Charles and we continue to work that with our partners in Lake Charles, ETE, to see if we can optimize the commercial construct and we can further reduce the cost. And then of course we have options in Indonesia, in Tanzania and in Australia that we continue to work, but they are on a longer time frame than let's say the next 18, 24 months in terms of potential investment decisions. And then the other 2 that we are involved in and you can see it on the map on one of the slides in fairly mature but still uncertain commercial discussions are indeed the Northfield expansion in Qatar and the Baltic LNG project in Russia, both of them potentially very competitive source of LNG. And then briefly to the last part of your question, where does it fit competitively in the industry? I think our material gives quite a few data points that underpin the assumption that this project will compete very well with U. S. Gulf Coast Energy with any U. S. Gulf Coast Energy. And since there's quite a lot of it, we do believe that that is the marginal price point in the market. The $1.50 that Jessica mentioned and the half of that we are able to keep in our pockets is the illustration there. So in that sense, it will be well placed. Obviously, Qatari Energy is the cheapest energy in the business. And we cannot compete with Qatar on a cost basis, nor do we need to because of course the country government isn't going to give that cost advantage away to either investors or to customers. If we have to keep that cost advantage themselves as they rightly should do so. So even in the broader mix of LNG projects that are looking to get to FID, we believe LNG Canada will be very well placed to be a profitable and affordable supply source for customers and profitable for the investors. Thank you. Thank you, Mr. Today's next question is coming from Mr. John Rigby. Please go ahead, sir. Yes, thank you. Could you just talk about the upstream a little bit and if you could talk about sort of thought process and the decision making you have to go through in deciding whether you source gas from 3rd parties or self source it? And to that point, given that you've taken the LNG into your portfolio, if you were to self source, can you book those reserves now? I guess, the LNG market is becoming fairly liquid and price discovery is somewhat easier. That's my main question. Just a follow-up to the last question. You missed out Nigeria Train 7, I think. Was that just an oversight? Or was there a message there? Thanks. Hey, John, good afternoon and thanks for your question. Yes, definitely an over an oversight indeed. I was talking more about greenfields. So let's start with your last question. We have a very promising looking expansion in Nigeria that we are working on. And of course, we have the expansion in Sakhalin as well that we are that we continue to mature with our partner. So the brownfields are on top of the funnel of opportunities that we that I discussed earlier. The Upstream and indeed this gives us a very interesting source of optionality that is a little bit like but not entirely like the optionality that we have in Queensland in Australia, where we produce where we want to produce into a limited domestic market and we can make decisions to either make or buy on a kind of online basis. And that gives us optionality that we don't have in many more traditional LNG projects. In principle, we have enough upstream resource to supply most of what this project needs. We will always want a little bit of AECO supply in order to keep that option open and in order to have fallback in case anything happens on the upstream side that we need more acre supply. But other than that, in principle, we will have enough resource to fill most of our requirement here. But of course, if prices are anywhere near what they've been recently, we will make even more money buying gas from the market. And our Shell Energy North America unit will be very astutely looking at the optionality here and essentially instructing the upstream organization on how much to drill and how much to develop and put on stream in the kind of near term outlook and procure the rest of the market. And we believe that will have significant optionality in it that is not part of the base case economics that we paint here, but it is essentially an upside only game that we will be able to play in this market. So we can self source. And if we self source, particularly to the extent that we give a long term internal commitment to the upstream, that does change the economics of the reserve bookings from where they were in the past. I will not risk giving you any impact on this. But clearly, if we are able to see through a 40 year export license and a very long term short that we hold and the certainty that we will at least produce some of that, if not most of it, then that has an impact on reserve bookings. I think that's That covers it. Thanks, Martin. Thank you. Thank you, Mr. This next question is coming from Irene Himona. Please go ahead, ma'am. Thank you. Good afternoon. I had two questions, please. Jessica, you estimate an integrated project IRR of 13% from upstream to trading. You give us the cost of the 2 liquefaction trains at €14,000,000,000 What order of magnitude are we looking at for the total integrated project cost, including upstream and pipeline, please? Secondly, Maarten, correct me if I'm wrong, but it seems to me this is the first LNG project launched without having presold on long term take or pay basis. So you're not transferring the volume risk to the buyer. How should we or how do you appraise the way risk changes for this project given that effectively you're looking at all spot sales potentially? Thank you. Martin, do you want me to start and then you take the second question? Okay, great. So thanks, Irene, for the question. So indeed, the project IR is 13%. We consider that to be very competitive given the scale and size of the project. Indeed, it is an integrated return we're providing. I'd also note there is further optionality and potential to grow value. As Martin mentioned, and I believe I mentioned, we could potentially take FID on further trains in the future. And that's a source of important option value and also the embedded options that we have with respect to gas supply that Martin was just speaking to. So overall, feel very, very confident and comfortable in terms of the return profile of the project. We've tried to be particularly transparent in terms of the way we've presented the project at FID to give a lot of proof points in terms of the competitiveness as well as the underlying cost in terms of the cost per ton and some of the shipping and gas assumptions we've been making as well as the revenue assumptions we're making. So I think hopefully we've provided all of the key elements for you to understand the overall nature of the return profile as well as the cost base. Martin? Irene, thank you for the question. I think it is an important moment indeed for the industry that a project of this size is launched in this way without project financing and with the most the biggest shareholder essentially taking all the volume into its portfolio. And I think that's probably iconic for the way the industry is developing and it plays to the strength of the approach that we have adopted with a large portfolio and with a significant balance sheet and with a very large variety of shorts around the world that we can fill. Of course, it's also important to note that our joint venture partners, for example, Covance and CMPC will simply take the volume into their own short in country. And I can't speak to the level of commitment that Petronas and Mitsubishi Corporation have achieved. But we certainly haven't pre sold all the LNG. And we intend to use this model for making investment decisions going forward, which doesn't mean that we will have we'll take an unlimited loan position over time, but it does mean that we are very confident that with the years that we still have between now and the on stream days of this project, we will manage this part of the portfolio as in a prudent way. And then we have several options to manage it. As you point out, we could decide to leave some of it spot in the end. And I'm quite comfortable doing a total portfolio basis, which is currently 70,000,000 tonnes but growing to leave about 10% of the portfolio open for spot trading. We've had good experience with it lately. But that's again on a total portfolio basis. But we have several other options. We still have we are in very significant conversations with term customers to take 10, 15, 20 year commitments, very much the type of classical commitments that would normally underpin the project. It's just that we're not in a rush to complete and under pressure to complete the conversations because we sell from our portfolio rather than have to presale to FID. But there are 2 other sources. There is the access to markets that we create. We have recently bought Total out of Franceera in India, which gives us 100% control and access to an important import option into India where we are aggregating demand behind the terminal and can create a significant short there. But there's also smaller examples where we won the import rights into El Salvador and we won a big tender in Bahamas and a number of other market access plays that you would not normally use to intervene in FID in the classical way, but it will give us long term market access and long term shorts that the Canadian LNG will go into. Energy to transport to shipping where we successfully completed our 1st ship to ship transfer in Rotterdam to a Shell crude carrier yesterday is another sector that will develop as a major short in the 2020s that LNG Canada will be well placed to serve. Not necessarily from and we may do some of that actually here in Canada. But to the extent that we do it in other parts of the world with LNG Canada will simply displace that volume in our total portfolio. So I don't intend to be long by the full 5,600,000 tonnes by the time this comes on stream. We have a number of options to place into the market and we will take our time to do it profitably. Thank you. Thank you. Thank you much, Ben. We'll now go to Biraj Borkhataria. Please go ahead. Your line is open. Hi. Thanks for taking my questions. I had a few. So, Martin, you talked about the significant trading optionality of being so close to a demand center. Could you just clarify whether you've included any of the upside for trading in the 13% IRR estimate? And the second question is on Phase 2 of the project. Do you expect to complete Phase 1 first and then FID Phase 2? Or could we see the FID for Phase 2 before first gas? And then finally, just a quick one, on the carbon intensity, is it are there any figures you can give around that in terms of CO2 per ton produced and how that compares to the average in your LNG portfolio today? Thank you. Thank you very much, Biraj. Excellent questions. First of all, very limited trading optionality has been included in our base case economics and our 13% IRR. We typically do these projections based on kind of long term flat out levels of prices, whereas of course in the practice we see volatility in prices and volatility in trading windows opening up. So we expect the optionality both in the sourcing of the gas and the trading optionality in selling the gas to be elements to our economics which makes me even more satisfied with the 13% base case that we are presenting to you today. And indeed this does give make the portfolio a lot richer in terms of optionality. Phase 2 is a good question and we haven't settled on that. There will be an optimal point in time to consider Phase 2 from a contractor perspective when people are basically rolling off Phase 1 and you can retain them to immediately start work on Phase 2. And so that is an important moment to keep in mind. Secondly, we will want to have done some we will have some time to learn about how it's going and where we can further improve. And thirdly, of course, it will depend a bit on the affordability in the market situation by the time this comps. So I think we're leaving our options open at the moment as to when to consider exactly Phase 2. But clearly based on an existing pipeline and all the existing infrastructure that Phase 2 will have superior economics to Phase 1. And so in principle should be a very attractive opportunity in our own portfolio and compared to industry. So I'm certainly excited about going after that. But the timing will keep a little bit of optionality open at the moment to be informed by all those factors. But it could well be before 1st gas as per your question. The carbon intensity of this LNG plant is the lowest in our portfolio and the lowest that we know of in the industry at 0.16 per ton. Tonne. That is that I think is world class. And the carbon intensity of our gas production in Montney is also very low. And so together this whole chain including upstream and midstream complies very easily with the methane and the CO2 aspirations that we set for this for the LNG business. So this is a very low CO2 LNG chain. And so in a world that becomes more carbon constrained, I think LNG Canada's advantage will simply further extend. Great. That's really helpful. Thank you. Thank you, Mr. We'll now take questions from Mr. Alsair Syme. Please go ahead, sir. Yes. Hi, everyone. Two quick questions on the economics. On the 850 breakeven, can you give us an indication of what inflation rate you can see in the revenue side? And secondly, you mentioned in passing the fiscal package that the I guess, it's the provincial government that's put together. Could you sort of broadly outline what key components to that are please? Sorry, Alastair, could you repeat the last bit? You were breaking up at this end. Sorry, it was on the fiscal package that the provincial government has put together. Can you just outline what the key elements are? Yes. Thank you, Di. The activity is indeed a real terms kind of middle of the road Tokyo Bay JKM estimate that we use. We obviously use a range. We'll go as low as €650,000,000 and as high as €10,000,000 to test our projects and beyond because we've seen certainly recently prices go beyond well beyond that range. What of course and we do believe based on fundamentals that that is a cautious revenue assumption particularly if you take into account the trading optionality that we see on top of this. But what is indeed also important as we said in the presentation is that there will be times when energy prices are lower than 8.50 but the marginal production cash production cost of this project will be very, very low. And so this project will be cost and in all likelihood earnings positive almost any imaginable market outcome in the next 40 years, which makes it a very strong cornerstone of our portfolio going forward. But the straight answer is, it is RTE inflated, the price assumption of €850,000,000 that gives us the 13% IRR with the optionality upside that I mentioned earlier. As to the fiscal package in the province, there's an element of removing what was previously adopted as an LNG context. So initially, the province had a number of additional fiscal measures to take rent from the LNG industry. These additional measures have been largely removed in order to make the project competitive with projects from the U. S. And other sites. And to quite a large extent actually provincial measures have been about leveling the playing field with other industry actors in terms of giving us the same electricity rate, making the project giving the project an energy intensive trade exposed status, which is again a common designation for industrial projects in BC, but we didn't have that. And we're being allowed to defer the PST payments, which again is uncommon for projects, well, projects this size haven't happened before in BC, but for industrial projects. So to a large extent, I would say it is more leveling the playing field against other projects than giving particular incentives that will be special to LNG Canada. From the starting point, all of that has helped to has really helped to bring the project to an investable status. Martin, can I ask, are you exposed on carbon prices from the differential or federal government if they change over time? The carbon price system in BC is such that if you build a facility that is carbon advantaged compared to its compared to industry average, which this plant certainly is, you benefit from a low carbon price in the from a low carbon price that the project will pay going forward. That I don't think is fully legislated yet. I think that is still going through the various channels. So it's proposed legislation rather than firm. In our calculations, we have not yet counted on that coming through in the 30% that you see. So that will be a upside to the economics. And we think it would and we do believe it will be an appropriate measure for the province to proceed with in order to give incentives to industry to become carbon to invest in carbon friendly plants. Clearly this has been tested versus a variety of carbon price outcomes in the future. Also global as you know we're an an advocate of global carbon prices or global carbon taxes, which is also why we take a particular time to invest in the right equipment and the right power sources to make this project low carbon such that in a high price carbon world this will actually be this will add to the competitiveness of the project rather than detract from it. Great. Thank you very much. Thank you, sir. We'll now go to Mr. Rob West. Please go ahead, sir. Your line is open. Hi. Thank you and well done for getting LNG project over the goal line. I'd like to ask the first question about the financing of the project. And in your 13% IRR that you've disclosed, is that before project financing or does that include some leverage in there? And just if you could talk a bit about how you intend to project finance this and that would be helpful. The second maybe is a bit of a question for Claire. I'm aware you've given the number of the $1,000 per tonne on the liquefaction. And I'm aware that's a very round number. And I'm wondering, is it a round number in sense that there's still some uncertainty in that? Or is it really fully locked in? And just as a final component, if there was something that was going to sway that upwards or downwards, is there any particular area where you're excited you could still trim some of the cost or any particular area where you might worry that's the area to focus to make sure you don't have any inflation coming through? Thank you very much. Yes. Thanks, Rob. On the financing, I can be short. It's equity funded. And so there will not be any more financing. The 30% is an equity IRR with no financing leverage in there. So that was the easy question. And for the more difficult question, I am very happy to hand over to Claire sitting next to me. Hi, Rob. No indeed, dollars 1,000 per tonne and you may have seen that JGC Fluor, who are the contractor consortium, would have released their numbers. And in fact, that's a $14,000,000,000 contract on a lump sum basis. So that's where the $1,000 per tonne comes from, relatively simple calculation. Obviously, we work really hard to look at derisking the project in every sense and using standard technology, using Trident tested modular construction methods in Asia and really working very intensively already with JGC Fluor to drive extremely high efficiency and productivity to give everybody confidence that that's going to deliver. But indeed, it's the construction cost of the lump sum EPC. Great. Thank you very much. Thank you. We'll now take questions from Mr. Colin Smith. Please go ahead. Yes. Thanks for taking my questions. First one, just you were quite careful to qualify Gulf of Mexico alternatives as being greenfield. Obviously, there are brownfields where you'd expect the cost to be even lower and $1,000 a ton compares to the $500 or $600 a ton that have been talked about the cheapest LNG capacity on the train side being built. So I just wonder if you could comment why LNG Canada ended up coming above, say, Lake Charles? And then just on the pipeline, can you just comment on where the actual physical supply of gas, if you buy it in, comes into the system? Does that go through TransCanada's new pipeline? And then finally, could you talk a little bit about what you're proposing to do on shipping? Thank you. Yes. Thanks very much. Indeed in the kind of graph that we that is part of the slides that you'll be able to download from the Investor Relations web, we use a typical greenfield example from the GOM. And indeed some of the brownfields including Lake Charles are probably a bit cheaper than that on a dollar per tonne basis. However, we haven't found yet the GOM project that is able to counterbalance the $1.50 that Jessica outlined in her opening. So that fundamental advantage is difficult to counterbalance by building a cheaper plant. The fact that the plant in Kitimab is structurally a bit more expensive to build, has a number of factors. First of all, it is a remote location. So we fly in fly out construction workers and we build a camp and then obviously adds the cost to in the Gulf of Mexico. There's a large and deep contractor workforce that is basically available around the various sites. There are labor rate and labor productivity differences to note as well. And so that all drives our cost. And of course, we need to build a pipeline that is dedicated to the project and that is almost 700 kilometers long. If you build in the Gulf of Mexico then you're typically very close to a pipeline system and you just pay the tariff rather than to build a dedicated pipeline. So there's a number of reasons why we always knew that essentially the dollar per tonne cost in Canada would not be cheapest in industry. But the work has really been we also knew that it's $1.50 which I think is a relatively cautious estimate of the fundamental advantage. And what's there to be had in case we could really optimize the construction side and I do believe we've achieved this. The link into the gas system does not depend on any other line than the one that TransCanada is going to build for us, so the Coastal GasLink. There is about 5 PCF of gas production in British Columbia. So there's a large liquid market and the CGL line that we'll build will connect into that system and we'll be able to essentially, if we want to, take the full load for the plant out of the liquid market. It is likely that a number of the proponents of the joint venture will actually produce their own gas and put it into the system. But in principle that market is deep and liquid enough to take care of this. But we don't depend on any of our pipeline development to make this link if that helps. And shipping? So shipping, yes, we have deep shipping portfolio. We have 90 ships in the fleet today. So we typically don't make project specific shipping commitments because there's so much optimization that goes on. It really depends on the demand patterns that develop. Of course also it doesn't take until the middle of the next decade to build ships. So we don't need to order them yet. So we need to see how the rest of the demand supply footprint turns out over the coming years. And we will be buying a number of ships also to replace a number of older ships in that 9 gs ship fleet. Whether the extent to which we need to enlarge our portfolio is something we'll decide in a few years' time when we have a better view of the global optimization that is possible. But one of the interesting points of course is that by building this supply, it gives us 5,000,000 tonnes, 5,600,000 tonnes, 10 day shipping from Tokyo and which are currently contracts that are being serviced from further out, the Middle East and occasionally even from Africa. So by putting LNG Canada product in the mix, we will save on shipping. So we definitely don't need an additional amount of ships just that will be normal to the amount of LNG we produce. It will be less than that and how much less we'll decide near to the point in time. Thank you. Thanks, Wintzer. The next question is coming from Mr. Blake Fernandez. Please go ahead sir. Your line is open. Thank you. Hi there. Thanks. Jessica, I think this would be a question for you, but it's on the progression of spending. I realize that the CapEx falls within your range of $25,000,000,000 to $30,000,000,000 but I believe that guidance is through 2020 and obviously this project spending will go beyond that timeframe. And so I'm just kind of curious how the ramp up will go or how ratable it is? And then the second question, if you could just remind us compared to your $8.50 I'm sorry, the $8.50 to meet your 13%, what are the current spot market looking like? Thank you. Thank you, Blake, for the question. And I'll take number 1 and then maybe Martin or Claire, you want to perhaps share some thoughts on the current market conditions. In terms of the progression of spending, and Martin touched on this earlier as well, as we have some of the larger projects coming on stream in the next couple of years, it creates capacity in our capital investment profile. And this project fits well within the $25,000,000,000 to $30,000,000,000 range. I would say it's consistent looking into the early 2020s as well. So of course, we do planning on a much longer timeframe than just out to 2020. We're looking at our capital profile and the investment needed to achieve our strategy through the 2020s. And all of this spend and potentially subsequent FIDs in the LNG business fit within the capital profile and the ranges that we've indicated and will allow us to achieve our strategic ambitions. So it all fits. Maarten, do you want to talk a bit about the market? Yes. Thanks, Jessica. The LNG spot market has been strong this year. We've hardly had a summer season and then we haven't had a soft summer season either. And in spite of quite a lot of LNG coming on stream, the market has been demanding. At the moment, and this is Friday, I haven't looked yesterday and I imagine that yesterday's oil price increase would have strengthened sentiment. But in the last few weeks LNG spot has been in the kind of mid-11s 11.3, 4, 11.5. So 11.5 on 11.50 on Friday. That's for prawn supply, so then we're talking about November. The winter is very strongly priced. So at the moment winter cargoes are really quite scarce and are trending towards oil parity which would be 16%, 70% of oil. So that depending a bit on where the market goes looks to be a strong winter for LNG. And as far as the spot market is liquid into kind of March, April, we still see this being a double digit market. So at the moment and I think as the year closes, we will be living in a double digit spot price for LNG market. And so the near term outlook is strong. Then of course there's still a lot of energy to come on stream in the kind of second half twenty nineteen, 2020. So we could see the market being relatively well supplied in that period. But after that, as you could see in our presentation, it's pretty barren in terms of new supply coming on stream. We let up in the structural demand growth. So we believe that the underpinning price here is relatively cautious and rightly so. And certainly in today's market, this project would have very different levels of profitability than the one that we are communicating to you. Thanks, Blake. Thank you very much. Thank you, much, sir. Today's last question is coming from Jason Gabelman. Please go ahead, sir. Your line is open. Thank you. Yes. Hey, thanks guys for taking my questions. I just have a couple. Firstly, on Slide 6, you say the cost of supply is $2 per end. Is that including full cycle upstream CapEx and the cost to ship on the TransCanada pipeline? And if not, can you provide that figure? And then on the 13% IRR, I'm assuming you've looked at what the IRR would be on a full build out with 4 trains. I'm not sure if you have that in front of you or willing to provide that. And then just in that vein, it sounds like part of the consideration to wait to take FID on the next few trains are labor availability. I mean, is that the number one consideration when you're thinking about taking FID on Trains 34 in addition to the overall, how demand evolves or is there something else that you're looking at? Thanks. Yes. Thanks, Jason. I can confirm the Upstream $2 number does include full cycle capital to produce that gas. It does not include the cost to transport the gas through the coastal gasoline pipeline. So although the transport cost is obviously included in our total return calculations, the $2 is to produce gas in the Montney on a full cycle basis. The IRR for Train is not something that we'll share today. As and when we consider that project and if it does come to FID, we will give some transparency into the economic attractiveness of that project, but that will be too early to do today. And also because we don't have mature enough estimates of the cost in order to give you such a number. So it will be a bit speculative anyway. I think considerations for that expansion will be multiple. We'll definitely look as to whether the LNG market is adhering to the instructions that we give to it when we produce the LNG market outlook, I. E. How is the market developing? Is the growth indeed as deep and as broad as we see it? I think that will be probably the main thing we look at. But we'll also look at competing projects. What is the rest of the industry doing? Where is the supply coming from? And of course, as we've done with this project is to really make sure that the expansion would sit at the left side, the left hand of the cost curve of the options the industry has. Now it will be cheaper normally than the base project. So it is likely, But you never know what the industry looks like in a couple of years. So we will again put a test on it, particularly in the light of what project cost by that time, yards in Asia, how full are they, project activity in Canada, how active is it. In a scenario where oil prices stay high, you could see a more tighter contractor and a tighter labor market. And that could be a cause to pause for us. We built this infrastructure for 40 years. So you're married to the balance sheet that you create for a very, very long time. So if the cost picture isn't attractive enough by the time it would otherwise be optimal to make that build an extension, we would pause. But if it is attractive enough, then I would be very keen to build this out. So a number of considerations will come into it, labor availability being one of them, but it will really need to be the total picture of the competitiveness of that investment. I think that's the last question we took. So before we go back to the operator, I want to thank you for joining us for this hour and thank you for your interest in Shell and in Canada LNG. And thank Jessica and Claire for