Shell plc (SHEL) Earnings Call Transcript

Thanks, all for joining this session, where we will look into detail at Shell's integrated business strategy. We will start with a presentation from Maarten Wetselaar, Shell Director for Integrated Gas, Renewables and Energy Solutions; who is joined by Steve Hill, EVP, Shell Energy. [Audio Gap] I now hand over to Maarten and then later on to Steve for the Q&A.

Yes. Good evening, good afternoon and good morning, everybody. Many thanks for joining our second session today, which is a Shell's focus session on the integrated gas business. Following Shell's overall strategy of day 2 weeks ago and the publication of our LNG outlook earlier today, I really look forward to an opportunity to talk about our business and our business strategy in a bit more detail. For those who are not on the call earlier, my name is Maarten Wetselaar. I'm the Director for Integrated Gas, Renewables and Energy Solutions, and I will be joined for the Q&A by Steve Hill, who's the Executive Vice President for Shell Energy, in charge of all the LNG, gas, power and environmental products trading in Shell and in my business. Before we dive into the details of the IG strategy, let me start with a brief recap of the Shell overall strategy that we presented to you 2 weeks ago. With our Powering Progress strategy, we will accelerate our transition to a net-zero emissions company by 2050, delivering value for our shareholders, for our customers and for wider society. The accelerated synergy is built around a disciplined approach to managing capital and carbon. Shell has itself set a net-zero target for 2050 that is comprehensive and complete, with short-term targets between now and then to really get going. Shell is changing to be a more focused, more resilient and more competitive business for the energy system of today and the future. This strategy means transforming the markets we operate in and the sectors that are difficult to decarbonized such as aviation, shipping, road freight and industry. Carrying out this strategy will radically transform the company's portfolio in the next 30 years, and it will deliver compelling returns for our shareholders. And Shell is already well-positioned for the enormous commercial opportunity of the energy transition. With our differentiated strengths, we have a footprint at a scale that others aspire to have years from now, which create a unique platform to provide the lower-carbon products our customers want and need and start to demand. By 2050, the majority of our energy products would come from renewable sources. And all the fossil-based carbon that we would still sell would either be captured and stored, balanced out through nature or be embedded in materials. Shell's [ research ] organization will deliver the net-zero target through 3 pillars: growth, transition and upstream. And the Integrated Gas business is in the transition pillar because it's highly relevant to the transition and highly geared to the transition. We have the assets and the product networks to enable the transition and to serve as a platform for a growth pillar. Now briefly on the role of gas in the energy transition. Because natural gas helps to provide cleaner energy, it emits between 45% and 55% less sales to than coal when used to generate electricity, and air pollutants are only a fraction. More than 750 tonnes of CO2 emissions have been saved as a result of coal-to-gas switching over the last decade. The environmental benefits of gas also include the reduction of air pollution. Many cities across Asia have seen significant improvement to the air quality from coal-to-gas switching. And Shell is playing a leading role in the industry efforts to continuously reduce emissions of methane, a highly potent greenhouse gas in itself, across the full gas supply chain. We have established and we lead the Methane Guiding Principles initiative. This initiative, which is an equal collaboration between industry and civil society and academics. The more other actions has developed best practices and initiated an executive outreach program to create awareness and drive down emission. Shell has also set an industry-leading target to maintain its methane emissions below 0.2% by 2025 for all the oil and gas assets where we are the operator. Now gas is expected to play a key transition role in decarbonizing the sectors as the world moves more and more to renewables. It's driven by replacing coal in power and industry but also by growth in, for example, freight transport, where we see the share of gas growing due to innovative products and technologies. Gas is starting to prove to be a flexible and competitive solution in other hard-to-electrify sectors like construction and the iron and steel industries. As you heard from us earlier today, these factors support the growth in gas demand of about 1% per year in the next 2 decades. But LNG continues to be needed to connect the gas supply and the demand growth because these are geographically disconnected. It will play a pivotal role in meeting energy demand growth, particularly in Asia. So energy will grow much faster than gas demand, and we expect it to grow by a compound rate of about 3.5% per year into 2040. And we expect natural gas to have a long-term role beyond 2040 and beyond 2050, and it has several pathways to reach net-zero itself, including CCS, biogas, nature-based offsets and hydrogen blending. With our innovation capabilities, we are extremely well-placed to develop these pathways. And I want to share perhaps a few good examples of what we're doing in this space. By the end of 2020, we delivered the industry's first 7 carbon-neutral LNG cargoes to customers in Asia, enough to power almost 1 million homes for a year. These carbon-neutral cargoes help customers offset their emissions and create differentiated products down the chain. As LNG penetrates the transport sector, we aim to scale a net-zero solution in the form of renewable natural gas. For example, in Germany, we're investing in biogas liquefaction plants, which will be supplying thousands of trucks with bio LNG. And we're also growing the LNG refueling stations to 50 bio LNG distribution points by the end of this year in 2021. As part of our integrated customer offerings, Shell is investing in CCS project in Northwest Europe that can help our commercial and industrial customers mitigate their own hard-to-abate emissions. For example, the Northern Lights project in Norway will store up to 1.5 million tonnes of CO2 per year. We will have the option to eject our own CO2 and from our own operations into that project, but we can also propose to share that CO2 storage with our industrial customers as part of an integrated energy package, where we're going to take back the carbon we sell them and store it under the ground. A very exciting commercial model. CCS is becoming a business rather than just a solution. Now with 70 million tonnes of LNG sold last year, we are the world leader in LNG, and we are positively leveraged to the growing role of gas and particularly energy and energy system. We're also the leading producer of gas and liquids products. Our business Integrated Gas delivered $11 billion of cash flow in tough market conditions last year. We have an unmatched LNG portfolio of demand and supply positions that is returning material and resilient cash flow to the company. From this position of strength, we will extend our lead in the growing LNG market, enabled by and supported by our world-class trading and marketing capabilities. We will continue with our successful strategy by adding competitive third-party volumes to our trading portfolio and selectively investing in new energy supply assets and expansions of existing positions, always with a focus on cash and carbon competitiveness. But there is further opportunity on the cost side. And with relentless focus on operational excellence, we aim to generate resilient cash long into the future. Running that business that has put us in the lead efficiently. By 2022, we want to reduce operating expenses in this business by around 20% compared to 2019. Now as the digital foundations are being established, digitalization starts to seriously improve all performance areas of our assets. For example, environmental performance, reliability and the productivity of our people. We are accelerating the deployment of digital technologies with a focus on high-quality and accessible data. One example of how we use digital technologies is real-time optimization across all our liquefaction assets and our GTL plants, yielding on average, 2% to 3% more production potential or efficiency gains, depending always, of course, on the gas supply situation. Now in GTL, we have no plans at the moment for new greenfield plants, but we do see opportunities to further develop premium markets and expand our unit margins. We have a clear competitive advantage in this space and still see significant potential to increase the value from our GTL assets through product sales, capturing a significant and increasing premium over Brent. Now energy systems are becoming more complex. And with that development, there is a clear case for system-wide optimization and integration of energy assets and networks. This requires flexibility, integrated infrastructure and state-of-the-art digital platforms. And in Shell, we see significant integration potential between our gas business, our integrated power business and our hydrogen business. And we are in an excellent position to generate increased returns by making these systems carbon and cost-efficient and by trading, optimizing and converting flows of renewable energy and LNG. Here's how it works. We will bring LNG, and over time, net-zero energy and clean power into an energy hub. And we can sell these in their own rights as gas or as green power. But if we didn't take the gas, we can also convert it into power and sell it or convert it into blue hydrogen. The clean power, we can, of course, sell us power, we can also convert into green hydrogen. And we can sell the blue and green hydrogen to transport customers to industrial customers. We can use it in our own operations or if the market demands it, we can convert it back into power. Integrated energy systems like that hold significant optionality and value potential for players with superior access to energy, superior access to customers and superior access to conversion assets. And Shell has a unique starting point on these 3 dimensions and intends to deploy this and extend this lead. On Strategy Day, we showed a number of examples of how our different businesses can integrate and the role that LNG and power play in is, and I will run you through 2 of these examples later on in the presentation. Back to the growing LNG market, where we are indeed well-positioned to extend our leadership. We see opportunities both in geographical expansion but also in growing new markets through more ways to use LNG, for example, in transport. Over the last 10 years, we have seen our share of the global LNG volumes sold increase from around 8% in 2010 to more than 20% last year, with more than 300% volume growth over the prior period. Last year, we supplied LNG to no less than 37 countries in the world. For example, we recently opened an LNG regasification terminal in Gibraltar. And as a result, Gibraltar switched from diesel fuel power generation to natural gas to a new gas-fired power plant, reducing CO2 emissions and improving the air quality around the Rock of Gibraltar. And the number of countries supplied will continue to grow. In the coming 2 years, we will provide the first energy to Ghana, Croatia, Hong Kong, and then there's more to go. We target development of 3 million tonne per year of new LNG markets by 2025. Now I mentioned transport, and I want to return to that, an important growth market, where we intend to grow into a material business by 2030. Shipping is where LNG is the cleanest fuel that's available today. Our aim is to supply at least 20% of the global LNG bunkering demand going forward. We already have the largest global LNG bunkering network with 6 operating bunkering vessels, and we've executed more than 400 ship-to-ship LNG bunkering operations to date. Our recent supply agreement for 5 LNG-fueled build carriers helps our customer BHP to reduce CO2 emissions by 30% and demonstrates the competitiveness of LNG as a fuel in shipping. We are rapidly expanding our own use fleet with more than 60 deep-sea vessels and barges on order. And we're also building an LNG for road transport retail network in Europe, China and India. The Chinese LNG for road transport market was 13 million tonnes in 2020 with more than 3,000 LNG filling stations and 140,000 LNG-fueled vehicles sold in the year, a growth rate of 30% year-on-year, a substantial growth rate that we kind of expect to continue in China for now. Shell China retail is already active in LNG refueling through joint ventures, and Shell supplied those retail joint ventures with 15 kilotons of LNG in 2020, 60% year-on-year growth. Small volumes today but growing fast. The European LNG road market is still small but anticipated to grow at a rapid pace and expected to be around 8 million tonnes by 2030. And we are the largest supplier of energy to road transport in Europe, having doubled our business in 2020, with 62 sites in 7 countries now except in the Shell LNG card and over 162,000 refueling transactions performed, a grand growing fast. More generally, we continue to innovate. We will lead the market with our world-class innovation, trade and optimization capabilities. We have a diverse portfolio with varying contract duration, flexibility and indexation. We will create new markets in Asia and beyond, embrace new customers in all sectors and expect most growth to be in the commercial and industrial sector. China and India will be key markets for us. So how will we grow our business and create new advantaged positions while we look for the most competitive source of LNG supply to further strengthen and diversify our portfolio? This means buying more energy from third parties, but also extending our own production capacity. We have included selective investments in our capital plan to expand our portfolio of LNG plants and to grow, of course, natural gas supply to keep the existing plants full. LNG Canada and Nigeria Train 7 projects have both dealt with the logistical challenge of -- related to COVID and are on track to be on stream by the middle of the decade. LNG Canada will deliver carbon-competitive volumes, and the unit technical cost of LNG in Nigeria, Train 7, is one of the lowest in the industry. In the near term, our CapEx is expected to be around $4 billion, similar to the last few years. If you look forward in our funnel, our future projects have an average IRR between 14% to 18% and payback before 2040. And we have set a hurdle rate of at least 12% for projects in Integrated Gas. We are progressing the design of the extension of LNG Canada in parallel to the projects under construction. And for producing plants, we focus on ensuring the longevity of our LNG production by developing competitive backfill projects, such as the Manatee Project in Trinidad and Tobago or the Crutch Project in Australia that will keep Prelude full for a long time. All our opportunities are cost-competitive. We have already reduced the unit technical cost of our project portfolio by around 40% since 2015 and any new projects where the unit technical cost below $5 per MMBtu. We are confident that our equity supplies continue to form a solid base for our growing trading portfolio. Now let me highlight 2 examples that I promise you, where we are bringing the energy systems integration in Shell and maybe bringing it to life. First of all, in Queensland. We have a number of ventures across the energy value chain. The case here is around maximizing value through optionality of supply and demand. We have upstream gas production with our QGC and Aero ventures. We sell the gas domestically or we liquefy it, and we export it through the QGC LNG plant. The domestic gas is sold directly or it's converted to power and sold through Shell Energy Australia. This used to be called ERM, the power business that we sold -- that we bought a year ago, which gives us access to an enormous industrial customer base for which we plan to grow energy solutions offerings. But we also provide renewable power and storage, and we have nature-based solutions to help offset emissions. So this example clearly shows the options we have in Australia by integrating across the energy system. We can direct the product flow and optimize the assets to ensure maximum value while expanding the offering for -- of energy solutions to our customers and optimize every day the way the molecules and the electrons flow. A second example is India, which is an important growth market to Shell. And we are transforming a traditional LNG regas business into a fully integrated gas and power value chain. India is targeting to increase the share of natural gas in its primary energy consumption from 6% towards its aspired target of 15% by 2030. Now starting with the optionality of LNG supply to Hazira and further optionality in the different parts of the chain. We are delivering vital energy to our customers, while at the same time, lowering regional CO2 emissions in Western India, providing air quality improvements and reducing costs for companies. Further steps in the decarbonization journey are achieved through our investments in Cleantech Solar, building solar installations that cut out sites and the customer sites, mangrove plantations. And additionally, societal impact is achieved in delivering power for more than 100 mini grids that support more than 5,000 micro enterprise customers. Now today, I have given you an in-depth overview of Shell's IG business, serving energy demand of customers in the transition to a net-zero world. I explained why we are uniquely positioned to capture the opportunities in the growing LNG market, and we'll excel and lead in this business for decades to come. And how we will create further value from adjacencies with our integrated power and our hydrogen businesses in these complex energy systems of the future. And finally, our belief that natural gas and LNG have credible pathways to a net-zero stages in their own right, making them an essential part of the world's long-term energy mix and central to our strategy of powering programs. With that, let me take your questions and invite Steve into the conversation. We can move to questions, please. John?

[Operator Instructions] Here is our first question from Thomas Adolff of Credit Suisse.

Two questions, please. You've talked about how digital will help you keep utilization rates high off the liquefaction trains. But earlier on, you also mentioned the lack of investment, which will lead to lower utilization rates. How do you see the base business performing in your portfolio? And then secondly, might go into a bit of detail, but essentially, I'm asking the outlook to 2030. Maarten, I think we've discussed this a number of years ago. Prior to the FID on LNG Canada, you had about 70 million tonnes of LNG sales. And if you looked out to 2030, roughly half of that would have expired, right, either aging hubs or contract expiries. And there were 3 ways to renew it, right, new equity FIDs whether brownfield or greenfield, new third-party offtake agreements or contract renewals or discussions. And I wonder, since then, what progress you've made on those 35 million tonnes you would have lost and whether you're comfortable to get to 100 million tonnes by 2030, which would be growth in line with the market.

Yes. Thanks, Thomas. On your first question, what we note is that the industry has not invested enough in upstream gas supply and in their own LNG plants in order to keep utilization up for the coming years. In our own case, investments in backfill gas have, by and large, stayed as we planned last year. What has happened -- so there, I don't expect much impact, although we do expect industry impact. What has happened is that we've pushed a number of turnarounds from 2020 into '21, '22 because we simply couldn't get the people on site last year during COVID. And that will give us a bit more turnaround time, a bit more plants off-line this year and potentially into next year, in order to kind of catch up with this turnaround and these turnarounds with the maintenance. But in our business, we have not seen a slowdown in, let's say, natural gas investments. But generally in the industry, we have seen that. So we do expect overall volumes to be a bit suppressed as a result. In our case, it's simply the shutdowns that will have a bit of an impact this year. To your second question, of course, we don't set volume targets or at least, I would hate to set volume targets. I'm sure Steve's team could sell 100 million tonnes this year, if they're really -- if I really told them to. But it would have a slice of business that either it doesn't create value or even distort its value. So the last thing I would want is for the team to feel that it needs to hit a particular number. But I get your question, it's also directional. Indeed, with the investments in Canada and in Nigeria, where we've FID-ed fresh volumes into the portfolio, which is great. We've certainly signed a good number of long-term purchase contracts in the market that will help fortify our portfolio. But there also still are a number of extensions to our business that are still ahead of us. I would mention, for example, Oman, which will expire in 2024 or the Equatorial Guinea supply contract that expires before the middle of the decade. So we have a number of areas where we have homework to do. And I can give you, and perhaps also Lucas if he's online, the peace of mind that when we make our cash flow projections for the medium term, any extensions that we haven't yet secured are not in those cash flow projections. So that really is only about business we know we will have rather than business that we hope to have. So there's potential upside there if we secure a number of extensions there. But I say to you this -- today and I said 2 weeks ago that we want to and will seek to grow with the market, which indeed means growing those LNG volumes over time in the direction of the number you mentioned. But clearly, a volume driver will be the wrong thing to deploy.

We will now move on to our next question from Biraj Borkhataria of RBC.

My first question is on some of your carbon-neutral LNG sales. Presumably, over time, that will make you more sensitive to the carbon intensity of the assets. And a few times in this presentation and previously, you've highlighted that LNG pile on that basis because of the hydropower use. But I've never seen any numbers associated with that. So are you able to highlight where that screens versus the industry? And then just some numbers would be helpful context there. And then the second question is a follow-up to Thomas' question. But when I think about options you have in the portfolio such as in the Qatari LNG expansion, maybe not specifically to that project, but when you look at decisions like this, can you talk about how you determine whether you want just the offtake versus having the integrated equity interest in the upstream and liquefaction going forward? That would be helpful.

Yes. Thanks. Let me take both. You're absolutely right that the carbon content of a cargo matters already to many of our customers. And I think it will matter more going forward. I would -- I can well imagine that becoming a spec of LNG that we trade -- and that we trade and that we optimize later in this decade more as a rule than as an exception. And therefore, indeed, if you want to sell offset cargoes, it really matters how much credit you need to apply depends on the carbon intensity. LNG Canada is less than half of the industry average of the carbon intensity and is the most carbon competitive -- will be the most carbon-competitive plant in the world. We haven't actually given the numbers, and it's something for us to consider. So we will think about whether we want to actually share the carbon intensity of it, but that's where it sits against the industry. So it is a step change, not just because it use hydropower but also because of all the other equipment choices that have been made here, which is very much has had carbon in mind. And also, the way we produce the upstream in Canada in Groundbirch. Although it's still gas, it's very, very low carbon because it's fully electrified and again using mostly hydropower. So it is very carbon-competitive. To your second point, we clearly like to have the offtake from competitive projects if we can buy it at a reasonable price, and particularly at reasonable flexibility. Whether we will invest or not really depends on the terms and offer and whether that investment gives us any more control over the scheduling of the plant, over what to do with flexible cargoes, et cetera, because that's often where value gets created actually on the interface of managing a plant and managing the trading portfolio. So the more input that we can have on how plants are managed and how the LNG is scheduled and how the shutdowns are scheduled, the more value -- the more optionality we can create. But at the end of the day, an investment will have to meet the return threshold and will have to fit into the overall return the IRR picture that we've given you that I talked about in my speech and that we gave you on Strategy Day.

We will now move on to our next question from Christopher Kuplent of Bank of America.

I hope you can hear me okay. And sorry, I had trouble with my phone line earlier in the earlier session. So one question on the macro, if I may, and one on the Shell strategy. Just wanted to ask the kind of outlook you presented earlier today. How -- or which scenario that you presented a couple of weeks ago that comes closest to, where I think Sky would probably lead you to a different conclusion in the next 20, 30 years in terms of looking at when global gas demand peaks. So I wonder when it's time to pick a different date rather than talk about 2040 in your LNG outlook. And the second question is perhaps along similar lines to what Thomas just asked, I wonder whether what you've experienced over the last year but also over the last few years of updating these LNG outlooks, you think the degree of vertical integration in our supply footprint is about right, no matter how fast you wanted to grow sales versus your upstream liquefaction. I hope that makes sense.

Yes. That makes a lot of sense. Steve, maybe you can take the -- you can come back on the first question after I have got the second one. The degree of vertical integration to me is almost a more important element in the portfolio than the exact market share that we have on the -- in the market. But when I talk vertical integration, I don't necessarily mean that I have to be all the way from the wellhead to the customer. It is more about the kind of -- about the flexibility that I have in the chain. So if I have an offtake agreement where I have a lot of flexibility, that to me is sufficiently vertically integrated to count. But trend lines -- assets or trend line trading agreements are -- can be elements of the portfolio, but they're not particularly exciting because they don't add value to the rest. They are only valuable in their own right. And given how competitive the industry is, these are quite hard to find. So we tend to find -- the way things make more sense to us than to others is through integration -- through vertical integration rather than on a stand-alone basis. Chris, is that an answer to your question? Or did I misinterpreted that part of it?

Yes. Yes, that's helpful. Just wondered whether you think the short position today is -- perhaps become more valuable than it was considering what's happened to the market?

Yes. I think we always try -- Steve and I always try to build portfolios that are -- that behave well in many market circumstances because it's so hard to predict where things are going. But Steve, let me give you the floor if you have a thought on that and on the other part of Chris' question.

Yes. So on Chris' first question. Long term, the outlook is somewhere between waves and islands. It's -- but you kind of dismissed -- and Sky has been a comparator. Actually, for the next decade, Sky is in the range. It's only after 2030 that, that has gas demand tailing off much more quickly. So from now to 2030, they're all relatively bunched together. Wave is at the top of the range and islands is at the bottom; our outlook in Sky, somewhere in between. After 2030, Sky falls off. And the outlook is probably at the -- in the higher end of the range between waves and islands. And sorry, I missed the second question. So I was looking at the first one in detail. If you could just repeat that.

One question, I just was wondering whether you had any further thoughts on that on integration. I would just add, perhaps, Chris, of course, the LNG outlook is basically an average or an interpretation of third-party outlooks. We don't overlay it with our own scenarios. And so what you see is that the third-party outlooks are more bullish on natural gas than Sky 1.5 but are somewhere in the range with the 2 other scenarios. And of course, what will actually play out is relatively uncertain. And therefore, what is really, really important is that you have affordable LNG, that you're on the left hand of the cost curve. So that if we get more of a Sky scenario that our LNG continues to be competitive in what, in that case, will be quite a competitive market.

Yes. On integration, I think that it's a concept that has a lot of value for us. Clearly, over time, the value in the LNG chain can move upstream and downstream. And our integrated model, it kind of gives us a position wherever the value happens to be at the time. And then the optionality that's created by having a chain with multiple supply sources, multiple shots, our own market positions, unlocks a lot of the trading value we subsequently capture. What really excites me, though, as well is the integration Maarten showed in his presentation about -- between gas and power and hydrogen and offsets in CCS and integrated cleaner energy system because we play in all those different parts of the market. And when you've got all those options in an advantaged network, that's a tremendously exciting opportunity for trading business.

Yes, and a business, I would add, that very few people in the world can play in. If you look at -- clearly, we have new competitors as we move -- that's not the topic of today, but as we move deeper into power, deeper into hydrogen. But many of the people that we meet in that business don't have this gas business, don't have that opportunity and that trading sophistication to optimize these energy systems. So I do and we believe that there is a significant differentiator going forward.

We'll take our next question from Anish Kapadia of Palissy.

Yes, I've earned some questions on project outlook. Firstly, I was thinking about the Eastern Med area because there's been an awful lot of gas discovered in that area. It seems like Egypt is getting its act together in regards to restarting LNG plants. So just really wanted to see your thoughts in terms of the growth in LNG from Egypt and potentially other projects coming either through Egypt, like Israel, Cyprus, some floating LNG, how are you seeing that playing out over the next 5, 10 years or so. And then secondly, just if you could give some updates on -- I suppose some of the lower-return, higher-risk projects in your portfolio such as Tanzania and the Indonesian projects in terms of those -- the growth potential there and how you're thinking about them.

Yes. Thanks. The Egypt situation is a fascinating one. And I guess if you're going to have an empty LNG plant anywhere, then the East Med is not a bad place to have it. Because every time someone drills a hole, they find gas, it seems, although not everybody, all the time. But there is clearly a lot of gas now discovered and a lot of exploration going on. And so almost certainly and fundamentally, our Egypt LNG plant that has not done much in the last few years will be -- will fit itself in the course of this decade. It is our task to try and get as much control over those molecules as we can commercially and potentially even economically and physically because then we can build the most valuable value chains. And that requires exploration, it requires commercial negotiation. And it requires a degree of political maneuvering because, of course, the East Med is not free of political position taking. I do absolutely believe that the East Med will be a source of significant -- that can be a source of significant value for us and, of course, positioned beautifully between the Atlantic and the Pacific Basin. So I'm optimistic there. I think between the guys in Egypt and Israel and Cyprus, we will find ways to orchestrate for that -- for enough that to come to our plant for that to be a significant source of value. To your other questions, that I wouldn't necessarily characterize Tanzania as a low risk -- or a low-return, high-risk project, I don't like low-return, high-risk. I would say it's more a high-return, high-risk project. It is very competitive and cheap to produce offshore gas and 16 Tcf of it, which is a fantastic starting point. That's like [indiscernible] volumes. And in principle, not so easy, not so difficult to get onshore. And in principle, you could buy -- you could build a very competitive, potentially modular, LNG plant onshore in Tanzania. The issue there really is indeed the political risk that we need to overcome. And we will only -- when we overcome it, we will push the goal with them. But I think LNG from Tanzania, fundamentally, is very valuable LNG, if you can get past the political risk equation. And so we're working with that, but not in a hurry. We have enough other places at the moment to build in. But if I can to take Tanzania over time an investment decision based on solid fundamentals, I will. And Abadi is a different story. We have decided to market Abadi. And again, that is not a low-return project. But in the total portfolio of assets we have on priorities, it simply doesn't, at the moment, attract funding. And the government and our partner are quite keen to get on with it. And for us, it will be a later project for later in the decade as things stack up now. So it's probably better if somebody else owns Abadi share only.

Our next question comes from Lucas Herrmann of Exane.

A couple of others, if I might. I can see it and I can feel it in terms of India, Australia, what you're doing, building out value chain. But absolutely no idea how to put a value on it or think about the incremental income that comes. So I guess the question or view is, how do you help me understand not the concept, but the hard financial benefit and when do you think we start to see it in a meaningful way? And secondly, perhaps slightly more cheeky. Mousetraps, Maarten and Steve, you like leaving them about. How did they work for you through this first quarter?

Yes, thanks, Lucas. Good question. Mousetraps is, by the way, the second reason, apart from the extensions that we don't count on in our projections is that the second reason why we're a little bit disappointed with our cash projection for the medium term. The -- we occasionally get successful with our mousetraps and that then flows through our results in the previous years. But of course, they're hard to put into your plan because it really depends on the events that are untenable, weather events or other events. And therefore, we see them in our actuals. We tend not to plan for them and it can look like. If you look at a stream of actuals that our medium-term projections are perhaps a little bit on the light side, but I wouldn't want to promise events such as the weather events. The -- your other question is a bit -- is hard to give you modeling advice on. In some hubs, such as the ones that we described today, that optimization is real today. And maybe Steve can talk a little bit, perhaps to the Australian example that is currently the most material one. The one that I described is also a system where hydrogen plays a big role. And of course, that at the moment, is still a projection. I do believe when hydrogen becomes, in the course of this decade, a more significant business, there will be a significant supply trading optimization element to it and those who can produce the cheapest green and blue hydrogen and mix and match and get them to the right place and have the right logistical control points, will have some significant advantages in the market there. Some of these hubs will take a little bit of time to construct, but some of them are live. Can you talk to -- do you 1 or 2 examples there, maybe, Steve?

Sure. Well, Australia is a very obvious example over the last year. We've talked earlier about LNG prices being at 20-year lows and all-time highs over the past year. You can think about QC LNG in many ways, but one way to think about it as an option between the Australian domestic gas market and the LNG market. There's obviously constraints on how that option can be utilized both within the constraints of the business and the government policies and agenda in Australia. But clearly, there's been times when the domestic gas price in Australia has been significantly higher than the LNG price and vice versa. So that type of flexibility is -- has a value for us. One of the other businesses we're growing at the moment is our power business in Japan. It's still a very small business, but we are a participant in the Japanese power market now, and we're trying to link our LNG business to our power business in Japan. And 2021 has already been an interesting year in terms of price environment. We've seen record-high prices for electricity in Japan. We've seen high LNG prices. We've seen high gas and power prices in the U.S. So the longer we create these value chains, the more options we have. The combination of the optionality of the value chain and the trading business, it gives us money to make that. And again, it's not just the -- capturing the optionalities. It's seeing these trends come. So by being in the Japanese power market, it's another way where we would get insights coming to us for what was likely to happen in the LNG market early in the year.

Yes. Singapore will be another place where between the gas and the power market and the significant own demand we have from our own industrial assets, we find very frequently ways to optimize the fact that we are the main LNG importer into Singapore and that we are a very large power consumer as well and increasingly can play in these markets -- these markets off against each other. So many opportunities, many big and small mousetraps. The one that you saw last year in our results in Q1 was obviously when we correctly caught the falling LNG price and benefited from that in the first quarter results. And we would always continue to try and prepare for these events. We don't always get them right, but it's definitely a feature of our business.

Maarten, if I was to ask you, if I look back at that particular slide showing operating cash flow and was to say, "Okay, over the last 5 years, on average, what was the trading income or the income that you managed to realize from the optionality that's inherent in your portfolio," would you be willing to disclose or put a number on it?

The answer is no. But it's always a positive number because otherwise, we don't execute [Audio Gap] then we simply stay with the base business. But as, of course, we've said a few times, it is not so easy to actually separate these things. If we're able to squeeze additional cargo out of LNG -- of Nigeria LNG out of Sakhalin and sell it through our trading system to a particularly well-paying customer, it's always a little bit difficult to say where the value was created. Was it in the reservoir in Sakhalin? Was it in the operator's decision to squeeze the extra cargo out? Was it in Steve's brilliant trading operation? And I'm also interested -- it is produced that result in the unique integrated business model that we have. So we don't actually make that sum. We make it on a legal entity basis. But that is just a transfer pricing discussion. We like to think of the business as integrated. So I know and understand why you're interested in that, but I can't actually give you the number. And if I had it, I probably wouldn't, but I don't have it.

We'll move on to our next question from Paul Cheng of Scotiabank.

Perhaps I apologize first because I want to ask one of the questions is on trading again. Just want to see that, Steve or Maarten, that whether you can tell us for your loan equity LNG sales, those that you purchase and then we sell you, those you purchase -- can you tell us at what percent those repurchases on the spot market and what percent is under long-term contract? And also that for the we sell that -- those we sell volume, what percent you actually get unknowingly in the spot market and what percent is on your long-term customer contracts? That's the first question. The second question that -- I think you're talking about the project retention will be 14% to 18% internal rate of return. That seems extremely high for a long lead time LNG project. I'm not sure anyone has been able to achieve it. So can you tell us that what your current portfolio is already achieving that kind of return? And what is the LNG Canada, your expected return at what commodity prices that you assume? And if I can put you in a side, you sold 7 carbon-neutral LNG cargo that have you seen any price deferential for the selling price for those comparing to your regular cargo?

Maybe first if you can hear me because my system is indicating that...

Now I can hear you.

Excellent. Okay. Thank you. Maybe Steve can think a bit about the percentage of spot and term in our purchases and sales and come back to both those statistics and the philosophy behind it. What we've indicated in our returns presentation is indeed 2 data points. It's the 12% minimum IRR for investments. And LNG Canada, we reported as 13% when we took FID. And that number stands, and it's at the middle-of-the-road macro environment. The higher returns tend to come in, for example, expansions. So only if I build a Train 7 in Nigeria with all the utilities and the tanks and the jetties and the skilled workforce available, then I tend to actually be able to sit in the higher part of that return. And of course, the highest returns come from the backfill volumes. So the 17% and beyond is if I develop an offshore gas field in Trinidad or indeed an upstream development in Nigeria or in Australia that feeds an existing LNG plant, where the only additional investment that I need to do is drill a few upstream wells. Then you really get into the very high IRR. So the portfolio consist of all these 3 of greenfields expansions and of backfill. The greenfields tend to sit at the lower end, but the backfills that will sit in the middle of that range -- or sorry, the expansions is in the middle of the range. And then the backfill upstream projects would tend to pull the range up, and that's how it works, if that helps. Steve, do you want to take the other question?

Maarten, what oil price assumption you were using at 13%? You're saying mid-cycle, you said based on, say, $60 Brent or $55 Brent, will price. What year? Is it 2020 or 2017 when you sanctioned it?

It's -- we would always look at the year we sanction. We don't disclose the exact price. But the numbers you mentioned are reasonable.