Shell LNG Outlook 2020

Feb 20, 2020

Slides

Good day, and welcome to the Shell 2020 LNG Outlook hosted by Martin Betzler, Integrated Gas and New Energy Director and Steve Hill, EVP for Shell Energy. There will be a presentation followed by a Q and A session. As a reminder, today's call is being recorded. And now, Dirk Heisinger, EVP for Investor Relations, will give a short introduction before handing over to our first speaker, Martin Wetzler. Please go ahead. Okay. Thank you very much for joining us here. We are here in The Hague. Indeed, this is Gerard Halka. I'm leading IR. It's a great honor that we are here together again. This is the 4th edition of the LNG outlook. Indeed, as you've just heard, we'll have Marte Wetzlar, the Director of Shell Integrated Gas and New LNG's. And together with his colleague, Steve Hill, our EVP from Shell Energy joining here, we'll do a brief presentation, and then we'll go into Q and A. So let me hand it over now to Martijn. Thanks a lot. Thanks, Jerk. And for those who got confused, we're actually in London, not in The Hague. But other than that, I completely stand behind Jerk's announcement. Always an ending. We have a recording, so but I want to thank everybody for showing up in the London rain this afternoon and for dialing in from wherever you're dialing in. 4th LNG outlook, it's great to see this morning with the media and this afternoon with your interest. It serves a need. We will start with pointing out the cautionary note as that is unchanged since last time. And then we'll move on to telling you what you're about to hear, which is 3 key messages. 1 is gas continues to have a strong ride in the energy mix, helped by policy support, helped by strong availability and affordability, gas continues to penetrate further in the energy mix. And you will see us argue that it's a trend that we believe will be there for decades to come for good environmental and other reasons. Secondly, we'll talk a bit about how 2019 was a record year on the supply and demand side and how it played out in terms of various markets and prices. And the third point we obviously make that in spite of the gas market having had a very tough 2019, the investor side managed to take FIDs of more than 70,000,000 tonnes of LNG, showing really strong confidence in the future of this business, which we underwrite. But we'll talk a bit about the dynamics of that and how we see it all add up in the near, medium and long term future. Let me start with the first section. And so on the macro side, we continue to see a trend of growing population. The world added 750,000,000 inhabitants over the last 10 years, significant population growth. We see the world having well over 10,000,000,000 people by 2 1 over 9,000,000,000 people by 2,050. And of course, they will all strive for prosperity, and we'll go through them many of them will go through the middle classes cycle where energy usage per capita goes up a lot. And thirdly, there's a trend of increased urbanization. You can see on the bottom left of this slide, the urbanization rates in the OECD and in this case, China and India. And the you can see the potential for further urbanization. And just to point out that in China, the average energy consumption of someone living in an urban area is about 50% higher than if they live in a rural area. So for all these reasons, we are confident that energy demand will grow in spite of significant energy efficiency assumptions that we also have in our model. Energy demand has grown significantly, 1.5% per year over the last 10 years. And what you can also see on the top right hand side is that has remained strongly correlated with the CO2 footprint of the energy system that grew by about 1.4% a year every year, which means that that link that is so crucial to break in order to achieve made. CO2 isn't the only driver for the take up of natural gas, particularly when it comes when it replaces coal in the energy mix. Air quality remains a very significant issue. On the bottom right, you see 7 very large cities in the developing world. Together, they are the home to 145,000,000 people. And in between them, they had one city, had one single day last year where its air quality was in line with the WHO safe targets, which was Jakarta on 21 June. All the other days, all the other cities were unhealthy from a WHO perspective for the rest of the year. So air quality is not a very significant driver of gas uptake, particularly at the expense of coal. This year, you will see that this analysis goes until 2,040. So far, we also always used 2,035 as the long term reference here. But of course, as time has gone by for the 4th year, we think it's useful to go out that far. And as we go out that far, we see energy demand growing about 1 percent a year on average every year, which is slower than the last 10 years, but still significant over the period given the base. And it's more even more significant to point out, and this is an increase in assumption from previously, that 80% of that growth will be met by gas and renewables, 43% gas, 37% renewables. And if anything, there's upside to those numbers, as we will point out later. The second thing to note there is that this is the first time that this analysis projects a decrease in coal, so minus 10% over the period, where we see coal actually decreasing in absolute terms in the energy mix in the world. And why do I say this as upside? If I take you to the right hand side of this graph, you will see this depicts the evolving gas and coal market shares in the in a number of very material energy markets. And the way this graph works, where the arrow starts is the 2019 market share, and the pointy end of the arrow is where the 2,040 market share is projected to be. And there's a few takeaways from this picture. One is that across the 4 markets and globally, coal is losing market share 2019 to 2,040, and gas is gaining market share 2019 to 2,040. So the trend that is expressed on the left is illustrated here. But what is also illustrated is the further potential because you pick India and China and you see their projected endpoints for 2,040. You see in both cases on the right of that, in the case of India to the far right of that, you see the 2,030 target from the government. So there's real tension between what is projected here and what the government targets are. And even if the gas market in these two countries ends up halfway in between, that will be difficult to supply in the 2020s if that 2,030 target is halfway met. So we do believe that this has upside rather than downside in terms of increase in penetration. What you see in the IEA 2 weeks ago announced flat year on year CO2 emissions from the energy system. That was welcome news. That's the blue line on this left hand chart. It's, of course, a combination of advanced economies going down in CO2 footprint. You can also still see the threat from the red line that's going quite steeply up to the right top corner from the rest of the world. And both are opportunities, of course, to start driving further CO2 reductions going forward. But you see on the middle side here that coal to gas switching over the last decades has already saved cumulatively 600,000,000 tons of CO2 compared to the starting point in 2010. And that's equivalent to more than half of the emissions from South America for a full year. So that the flattening of the blue line is significantly enabled by coal to gas switching over the last 10 years. A different way to look at it. You can see that actually coal went down by 3% in global generation in 2019 on the left hand side. And that is significant, but it's particularly significant because it's mostly the result of global of policy. We now have 32 countries in the world with coal phase out commitments. Last year, 7 new ones of these 32, 7 were made that phase out commitment last year. And amongst them are 3 material ones: Germany, which is the largest call user in Europe Mexico, which is the largest call user in Latin America and Chile, which is the largest coal user in South America. In the European Union, we now have 13 countries with coal phase out plans, plus 8 that have already exited coal. And so we believe that this trend is wired into policy announcements rather than a random outcome that is about to be reversed. On the right hand side, you can see how the power current gas fired power capacity in these markets, and then the squares give the endpoint in 2,040 as currently modeled. So you can again see, A, the significant growth that gas is expected to have, but also still the very significant potential from the remaining coal footprint, particularly in the rest of the world markets and further illustration of the upside that is there. Coal doesn't only play in power, and this is back to the air quality argument. You can see on the left hand side here the share of coal in the industrial sectors in the countries depicted and then the use of coal and other solids, mostly wood in the household and light commercial sectors in the medium graph. And you'll see just how much this selection of countries overlaps with the air quality index on the right in 2018. And it's worth pointing out that the resulting often indoor air pollution from coal use at home killed 3,800,000 people in 2016, according to the World Health Organization. So again, CO2, but also air quality playing a big role. The potential of gas when it comes to air quality is nicely illustrated by an example from the city of Morby in Gujarat in India, where we have an LNG regasification terminal. Morby is a major in India and has fired that industry with coal gasification units over the last decades. As a result, the air quality levels were very, very poor, unlivable almost. If you look at the yellow bars on the left hand side, you can see just how bad the PM2.5, PM10 and SO2 concentrations were in 2017 in Morby. The Green Tribunal then intervened and banned the use of solid fuel gasification, and all coal gasifiers were closed within a period of 12 months. And you can see in 2019, how between March 2019 October 2019, the industrial sector in Morby tripled its gas demand and the industry was able to respond and how this had an impact on air quality in Morbid, which is the red bars in the left hand graph, the 2.5% dropping to well below 100 and the SO2 dropping to almost 0 and the city becoming much more livable as a result of a policy intervention that went from start to finish within 18 months, which just gives you a sense of the power of policy when it comes to cleaning up the air. Another important driver for the coal to gas switch is the fundamental trend for thermal load factors to go down. On the left hand side, you see thermal load factors in a number of important markets. And of course, with the increasing renewable penetration that we believe and argue is a one way street because the cost, the LCOE of renewables is competitive already in many markets, and its deflationary nature will mean it becomes increasingly competitive. These thermal load factors are on the way down, and that will fundamentally advantage coal fired gas fired power generation over coal fired because of its ability to respond in the moment and to dial up and down its production of power much more efficiently than coal. And on the right hand side, you see an example of South Australia, which is a market is very progressive, about just under 60% gas, just under 40% renewables. So very much a market that is, in that sense, there is a mix already far further along the transition than most. And you see there well illustrated how dips in renewable production are being managed are being caught by the gas fired power system delivering stable electricity to the people of South Australia. The other point to point out is actually that the South Australia is the home of the world's biggest battery that Tesla built, 100 Megawatt battery there. It's depicted on this slide in red in terms of its role. And as you can see, you can't find it. A lot many more of these batteries will have to be constructed before they start to play a meaningful role. And they will, no doubt. But for a long time, gas will be the fuel that makes the system work in South Australia. Now we like to point out all the reasons why gas is going to be great. It is also worthwhile pausing on the challenges that gas is overcoming or is having to overcome in order for the future to reach its full potential. First of all, there's methane emissions, which, as you can see on the left hand graph here, including the methane emissions that the IEA estimates on a global base for coal and gas. Gas on a greenhouse gas comparative basis is very advantaged compared to coal between 45% 55%. But its opportunity is to be much more advantaged because natural gas doesn't really need to have a methane footprint if it's well managed. So that orange bar there could be almost 0 if industry really manages emissions well. And it is certainly our intent in Shell to be as close to 0 as possible. We've put a 0.2% target out to be met by 2025. We're also leading co leading a worldwide coalition of players in the gas market together with NGOs, industries and multilaterals to promote methane reduction in the gas value chain as close to 0 as possible. And it's really important for us that we cash in on that advantage and make gas as greenhouse gas friendly as it can be. That links into the second step because gas needs a decarbonization story in order to play a long term role. And that will need to come from biogas, where you see a projection of significant potential for growth of biogas, which we can then blend into gas and sell low carbon products, but it will also need CCS to grow up, to scale up and become a major factor when particularly where gas is burned for industry or for power. So decarbonizing gas, taking care of the methane emissions and of course, making sure that affordability is never at risk, that actually governments can governments and people can commit to gas without worrying about overpaying across the cycles. These are three things that the industry should have in its own power and should definitely be able to address ahead of the curve. But we also need governments like the government of Morby in India, like many of the EU countries to continue to take progressive policy action to phase out coal and to come up with mandates for CO2 food prices that promote cleaner energy to support gas growth and of course renewables growth at the expense of dirtier fuels. And we also need to work on public perception. There is a risk that people take a shortcut and say, let's just forget about fossil fuels and just make a full bet on solar and wind to power the world, which would be a great thing if it was possible. But those of you who know about the energy system know that molecules are a very, very important part of delivering energy, particularly to hard to decarbonize sectors that cannot be electrified. And in those sectors at the moment are 80% of the global energy demand. We can see them go as low as 40% of the global energy demand, but still then, we will need clean solutions to meet those source of energy demands, such as steelmaking, petrochemicals, cement, fertilizers, aviation, shipping. There's quite a number of them that where electrification will be a very, very hard thing to do and where natural gas will be a long term play. Over time, biofuels and hydrogen will no doubt come into that mix. But if we phase out natural gas or if we constrain natural gas too early, we will actually lock in coal and other water source for too long, and that will be at the expense of progress on climate change. You can see on this slide the global gas demand by sector. It's by no means all power. Industry and residential and commercial play a big role as well. And you can see the emerging role of gas to transport as well, taking 9% of the total gas growth in the coming 20 years. And we'll come back to LNG to transport. To close out this kind of macro overview, it's useful to, first of all, look at how the total gas industry is projected to develop. And 40% of the projected 2% gas growth over the next 20 years will be supplied by LNG. So that will kind of double the LNG market share in the total global gas system. If you then break it down by region, you can see that Asia is still the major market, taking 3 quarters of that growth going into Asia in that period. And interestingly, if you break down Asia, the main story is actually not China or India, it is the rest of Asia. It's the smaller countries that are becoming significant LNG consumers over the period of time, and that will add quite a lot of resilience to the LNG demand that we project for 2,040 to be double the LNG demand that we see today, about 700,000,000 tonnes. I'll hand over to Steve to go deeper into 2019. Thank you, Martin. And 2019 was a quite an interesting year for the LNG industry. This is the 4th time we've done the outlook. A significant increase in new liquefaction capacity coming on stream. But if you look at the right hand chart, which shows the actual increase in volumes that we saw, it was materially the biggest year we've ever seen for new LNG coming to the market with a growth of 40,000,000 tonnes, so 12.5%. So this chart takes us back to what we were looking at this time last year. And we were predicting growth in the 30 something 1000000 tonnes split between Australia, the U. S. And Russia. And actually, what we saw was the supply growth being a little bit higher than throughput than expectation. And then the chart on the right shows the yellow boxes the range of forecasts for where that growth of LNG would be absorbed by the market. Growth of between 20,030,000,000 tonnes would come to Europe. And growth of between 20,000,000 and 30,000,000 tonnes would come to Europe. And one of the debates we were having this time last year was whether Europe would be able to absorb that amount of increased LNG or whether we would see an alternative mechanism to balance the market, presumably shut ins of U. S. LNG production. And what we actually saw, the black little squares, was that the LNG volumes that came into Europe were higher than the top of the range of forecasts. The LNG growth in Asia was a little bit lower than expected, which was driven by a reduction of imports in Japan and Korea. So when we look at individual countries, this chart shows the growth or the decline in imports in LNG in 2019 19 in orange compared to the expectation at the start of the year, the gray bars behind. And what we saw was that the 6 5 of the 6 biggest countries for LNG growth were in Europe, as Europe saw a 74% increase in overall LNG imports. The one exception, the one country not in Europe was China, which still saw a healthy 14% growth in LNG imports. And then if you look at the other side of the chart where we saw a reduction in LNG volumes, you have Japan and Korea, which we'll come to in more detail in a minute, but it's basically driven by a combination of higher nuclear generation in the power mix and the effect of mild weather. And then you also have reductions into Egypt and Argentina, and that was driven by those countries starting to export LNG volumes and therefore seeing a reduction in the net imports. So looking in China in more detail, continuation of what we've seen for the last decade. Gas demand growing at 12% a year, which was materially faster than the growth in domestic production, which we saw growing at 7% a year, creating an increasing need for LNG imports. Those LNG imports came from a combination of pipeline and LNG. But over the last few years, LNG had taken a disproportionate share of that growth. And in 2019, LNG accounted for 50% of the growth in overall Chinese gas demand. So when we look at Europe, this is the real story of how the LNG market balanced in 2019. And the first chart here shows how the market balanced on a supply side, on a demand side. So the gas demand in Europe in 2018 was about 500 BCM, and that increased to about 530 BCM in 2019. So the growth in LNG supply was much bigger than the growth in overall gas demand. And therefore, that was accommodated by a reduction in domestic gas production and a reduction in pipeline imports. And those reductions are shown in the other two charts on the demand side, that's increased gas demand. You look at the demand side, that increased gas demand in Europe came from a combination of a building storage and increased gas into the power sector. And the increased gas into the power sector was driven by coal to gas switching. Power demand in Europe overall reduced slightly in 2019, but what we saw was a change in the coal to gas switching action. So this chart tries to explain the coal to gas switching mechanism. And the price at which gas is competitive in the power mix is driven by a combination of the coal price, which is the black line, and the blue price sorry, the carbon price, which is the blue line. And those two prices will create a range of prices at which gas is competitive versus coal in the power mix. And that range, the coal to gas switching price range, is shown in yellow. The gas price is the red line on this chart. So you saw for the previous few years, the gas price pretty much sat at the top of the coal to gas switching price range and effectively that acted as a floor for gas prices in Europe. But during 2019, gas prices fell into the coal to gas price switching range, and that caused an increase in gas fired power generation and a reduction in coal fired generation. And that can be seen in the middle chart. So in 2019, we saw an extra 13% gas fired generation and a reduction of 16% in coal fired generation, which as which resulted in actually more gas being consumed than coal in European power generation for the first time ever. So parts of the growth in power demand in gas demand in Europe was this coal to gas switching. And the other big factor was an increase in gas inventory. And the chart on the right shows the gas storage level in Europe at the end of each year for the last 5 years. And as you see, there was a big increase the end of 2019. And this was driven by 2 factors. First of all, we went we've just been through a very mild winter, about 2 degrees warmer than the seasonal norm. And there's a relationship in Europe of about 1 degree's temperature versus the seasonal norm is equivalent to about 5 BCM of gas demand. So that 2 BCM would have reduced gas demand in Europe by 10 BCM and therefore, reduced increased the storage level at the end of the year. And secondly, the industry consciously built gas inventories at the end of 2019 in case there wasn't a resolution of the Russia Ukraine commercial issues and in case there was a gas supply interruption. So again, we saw very high gas storage levels at the end of 2019, and that allowed the increase in LNG supply to be absorbed by the European markets. So moving back to Asia. South and Southeast Asia was a very positive story last year. We saw growth in gas demand in all sectors in this region, but the dominant growth came in the industrial sector. And this kind of confirms the message that we've been saying that gas demand growth isn't all about the power sector. There's a big opportunity in the industrial sector. And secondly, when we look at where the growth in gas supply into South and Southeast Asia came from, it was all from LNG. The domestic significant growth in some of them in terms of LNG significant growth in some of them in terms of LNG imports. And then moving on to Japan and Korea, which was the challenging situation for the LNG market. If you look at nuclear share of the power generation mix, in Korea, it increased from 23% to 26%, in Japan, from 5% to 7% as more nuclear power generation came back online. So that reduced the demand for LNG in the power sector. And again, if you look at the middle chart, you'll see the average temperatures in Korea over the in Japan and Korea over the last 5 winters. And you see it was a particularly warm winter. Again, it was the warmest winter over the last decade, and that caused a reduction in LNG demand for the heating sector. So the combination of those two things meant we saw a reduction in LNG imports into these two countries of 7%. So I'll now move on to the United States exports. And the first chart here shows the amount of LNG being exported from the U. S. By month since the start up of exports in 20 16 and the markets to which the volumes have gone. So additionally, a lot of volumes stayed in the Americas, in Mexico or South America. But as U. S. Volumes ramped up, we saw a big increase in U. S. Deliveries into Asia. And then over the last year and a half, as U. S. Volumes ramped up even further, we saw an increase in the U. S. Deliveries into Europe. And then you'll notice at the end of the chart a particularly big step up in U. S. Production volumes as projects like Freeport and Cameron started production. And it was that spike at the end of last year that was part of the cause of the very weak market conditions that we see today. The weak market today is effectively a combination of this big increase of U. S. Exports that have come into the markets over the recent few months, combined with a very mild winter in both Europe and Asia and reducing demand and now most recently, coronavirus on Chinese imports. The right hand chart is really explains the previous China story, which was all around the U. S. Trade war and tariffs. So as U. S. Deliveries to Asia started to ramp up, those deliveries were split across China, Japan and Korea. But once the tariffs were introduced on U. S. Imports into China, we saw a reduction of U. S. Deliveries into China at the same time as overall U. S. Deliveries that despite these geopolitical issues that we see from time to time, the market is very effective at rebalancing and cargoes being lifted and customers having their LNG demand satisfied. So if we move on to prices, obviously, gas prices softened during 2019, and LNG spot prices also softened in 2019. The first chart shows the overall price level, and we see that the LNG spot price, which is the red line, tends to move between the ceiling of the crude oil price, which is shown in yellow, and the European gas price that is shown in blue. So when the market is tight, we tend to see the LNG price at the top of that range, and the oil price tends to act as a ceiling because above that, then you have various fuel switching options come into play. And the European gas price operates as a floor because so far Europe has been able to absorb all the LNG that's been pointed at it. The right hand chart shows the marginal economics of LNG exports for the U. S. So obviously, in 2018, we had a different set of market circumstances, and those economics were quite attractive. In 2019, many people forecast that we would see shut ins in the U. S. That didn't happen. I think what this shows is that the economics for exporting LNG from the U. S. Were got quite small, you know, quite marginal at times, but we never actually saw this margin get sufficiently low or negative to trigger shut ins to actually take place. In terms of the spot markets, the spot market continued to grow with the LNG market, but it kind of was stable at a 30% market share compared to the previous year. But we continue to see developments in how spot LNG is traded, both in the physical market and on the futures markets. So the actual trading of spot LNG is becoming more and more transparent. And in fact, we actually saw the volume of LNG traded as futures in 2019 be equal to the spot volume of physical LNG sold in 2019. In terms of contracting structures, no real change in the typical length or size of new long term contracts. We did see a reduction in the amount of LNG sold under long term contracts in 2019 versus 2018, but pretty constant compared to the previous few years. What was quite interesting was if you look at the mix of different indexations we saw in 2019, we had long term contracts signed using more different indexes than we had ever seen before. In fact, 2019 was the 1st year where we saw long term contracts indexed to gas prices in the U. S, in Europe and in Asia being signed. So when we take that position and look at what's going to happen in 2020, first of all, we're coming to the end of the wave of supply growth. Australia and Russia are just about done, so we'd expect maybe 20,000,000 tonnes of new supply growth in 2020, pretty much all coming from the U. S, pretty much all coming in the first half of the year. On the demand side, we would expect most of that supply growth to be absorbed in Asian markets and with Europe acting as the balancing market potentially with more imports potentially less than last year. This data is pre coronavirus. So if we were recreating today, we'd probably see a slightly lower number for Asia and either Europe adjusted upwards to offset or potentially shut ins from or turn down of LNG projects to balance. But 2020 is a year of transition for the market, so I think it's useful to kind of step back and explain how we see the market for a few years from the middle of 2020 going forward compared to what we've seen over the last few years. And this chart shows the growth in LNG supply coming to the market by quarter over the last few years and where the LNG has been absorbed. So we saw 3 years of strong growth and then a year of particularly large LNG supply growth over the last 4 years. But for the 1st 3 of those 4 years, we saw the market pretty much keeping up with supply growth and most that new LNG being absorbed in the Asian markets. Over the last year, it was a different story, and the particularly strong supply growth we saw was not able to be absorbed in Asia. And therefore, we saw a big flow of LNG into Europe, as we've discussed, which has had the impact on pricing that we've seen. Over the next couple of quarters, we have the last of the U. S. Trains as part of the first wave of LNG starting up. But from mid-twenty 20 onwards, we expect to see a significant reduction in the amount of new supply coming to the market for a period of around 3 years. And therefore, we expect to be back in a position where Asia and other non liquid markets absorb all the LNG supply and a tightening or a rebalancing of the LNG market. So if we move into the forward looking part of the presentation, we start with the amount of FIDs that we've seen recently that will need to be absorbed in the markets in the coming years. And the first chart here shows the amount of LNG that's been sanctioned each year for the past decade. And during the 2011 to 20 15 period, we saw a lot of LNG that was sanctioned, which the market has just finished absorbing. And what stands out is how high the amount of FIDs that was made in 2019 is compared to that. 71,000,000 tonnes of production capacity is a record for LNG FIDs by a long, long way. The other thing that this chart shows is how these new projects were structured, in particular how the LNG was marketed. So the area in red is where the project sold LNG to customers. And the area shown in yellow is LNG, which is off taken by equity participants in the project. And obviously, you see the equity offtake in 2018, 2019 being much higher than in earlier sanctions. And we think that this demonstrates a couple of things. It demonstrates the confidence of project developers in the growth of the market and the strength of LNG demand going forward. And we also think it is a structures of the markets, where companies are able to hold these volumes in portfolios and not necessarily back to back everything. And the right hand chart here shows who are the equity offtakers. So IOCs have some of that volume, but not necessarily all of it. National Oil Companies have a material piece of that demand. That could be upstream NOCs like Qatar Petroleum or downstream NOCs like CNPC in China. So when we look at the future supply demand balance based on all those FIDs, you end up with the left hand chart here. So the area in red is the LNG that is in operation today. And obviously, that sees a natural decline as projects come to the end of their life or gas reserves are depleted. The area in yellow is the LNG under construction, which is obviously significantly increased compared to last year because of the amount of FIDs. And then we have a little dash line above that, which is what the area what the volume under construction would look like if you assume the first four trains of the proposed cutter expansion move ahead. And the gray range is a range of forecasts of long term LNG demand. And this has also increased compared to last year. But this is a range of 4 different forecasts from 4 consultants listed below, 3 of which are pretty much bunched together at the top of the range and one is at the bottom of the range. So depending on your view of the market, the industry has now sanctioned enough LNG to meet demand to 2025 at the top of the range, maybe a few years later, at the bottom of the range. And the right hand chart here shows where that demand growth is expected to come from. And we haven't characterized markets by geography, rather by the type of markets. So the area in purple are markets where if you have gas demand, LNG is your only option. These are countries like Japan and Korea, which effectively launched the LNG markets. Has to compete with domestic gas or pipeline imports. So this is countries like China, which have provided most of the growth in demand for the LNG industry over the past few years. But most of the growth going forward is the area shown in dark green. And these are countries where LNG is not supplying LNG into existing gas production. So supplying LNG into existing gas infrastructure to meet the demand for existing gas customers. So removing many of the infrastructure and investment barriers for new gas markets. And then as you see at the top, we expect LNG as a bunker in fuel become a material source of demand over time. And digging into bunkering in a bit more detail, there's now almost 400 LNG fuel ships in operation or on order. And this is across most different sectors of the shipping industry, including some very significant demand sectors such as the cruise ship sector or the container ships. So the ships that are already in operation or under construction will have a combined LNG demand of about 2,500,000 tonnes a year. So the equivalent of a small LNG importing 37,000,000 tonnes, as shown on the right hand chart. Other forecasters have demand projections half as much again. China continues to be a very important market for the LNG industry. One of the questions we were expecting this year was, would China be able to absorb the supplies from the Power of Siberia pipeline, which is starting up at the moment and still bringing incremental LNG on top of that. And therefore, rather than just showing the demand said, to ramp up and then the rest of our forecast period. And as you see, between now and 2025, gas demand growth in China, driven by the residential and commercial sector in this case, is sufficient to account for the expected growth in domestic gas production in China, plus the power of Siberia, plus about the same amount again of other long distance pipeline supplies, plus further LNG imports. But as Martin mentioned earlier, the key markets for the growth in Asian LNG demand are South Asia and in particular, Southeast Asia. And this chart shows the expected demand growth by many of the key countries in these regions. So India, Bangladesh and Pakistan, representing most of the growth in South Asia and Indonesia, Malaysia, Thailand and Vietnam representing most of the growth in Southeast Asia. So as you see, in both of these scenarios, LNG is both replacing declining domestic gas production and provided incremental gas supply for gas demand growth. And the right hand side of this chart shows the projected LNG imports in each of these countries in 2,040 compared to today and how much LNG import infrastructure is either in operation or under construction. So some countries are pretty well placed. In others, there is significant infrastructure still required to be developed. But because most of these countries are existing gas markets, the infrastructure required is predominantly LNG regas and not necessarily all the downstream pipelines and power generation and other demand infrastructure. So that's the presentation. The key messages are gas is continuing to provide more and cleaner energy solutions, both because of its inherent advantages, because of strong government policy support and because coal is really being phased out of the energy mix in order to meet CO2 and air quality aspirations. 2019 was a very interesting year where we saw record supply growth exceeding expectations and the market succeeded in absorbing all that growth when there was a lot uncertainty around whether that would be possible at the start of the year. And that was particularly driven by the flexibility of the European gas market. And 2019 was also the year where we saw record investments in new liquefaction capacity, which we think was driven by the combination of strong confidence in future LNG demand growth and the lack of LNG FIDs that have been made in the previous 3 or 4 years. So I'll stop there, and we will welcome questions. So we'll start in the room, I think. And there will be also some questions potentially coming in online. If they do, then Timo will point out and we'll take those. We'll start in the room. Thanks for the presentation. Useful as always. If I could point to the equilibrium chart on Page 29, seems to indicate that since there's not a lot of negative coming out of Europe in the future, that Europe will need to continue absorbing similar volumes to what we saw in 2019. And that required relatively low pricing. So would you expect that we would continue to see TTF and MVP pricing essentially being set by the Henry Hub level? And then just as a follow-up to that, the pricing level was essentially being pushed down to variable cost of bringing Henry Hub into Europe. So should we think about Henry Hub plus shipping and regas is probably a floor level for European pricing moving forward? Yes. So I think you started by saying that we would see similar deliveries into Europe in 2019 as opposed to similar growth into Europe in 2019. So that's clearly what the chart shows, that Europe has absorbed a massive amount of incremental LNG. It has some ability to receive more because of the coal to gas switching flexibility hasn't been completely utilized. But we are in a position now where the European gas market has high levels of inventory and has a limit to just how much more LNG it can absorb. In terms of the pricing dynamics, we don't have any specific price forecast we're going to put out. Obviously, we're coming towards the end of the winter, so it's hard to see a big change in dynamics in the next couple of months. But as you get into the second half of the year, we then expect to be back in a world where LNG demand will be growing faster than LNG supply and LNG being out of Europe again and that will we think help the European pricing structure. In terms of that pricing dynamic that you described, that's pretty much where we are today if you look at the forward curves. So if you were see a much lower price in Europe, then you would be in a world of potential LNG shut ins in the U. S. To maintain that balance. It's Michele Della Vigna from Goldman. I had a question for you, Martin. When I look at the chart of FIDs on page 31, the 2019 number is quite scary. Scary in terms of scale, It's almost 3 years of potential demand growth for LNG sanctioned in one go. And also in terms of the contract structure, we saw little of it underpinned by long term contracts. And what I was wondering is how does this change your appetite to sanction new LNG projects? And also, on the side, when I look at the oversupplied market at the end of 'nineteen and the beginning of this year, one of the big reasons for that was the extraordinary growth in U. S. Exports. And a lot of these exports happened because the IOCs underpinned that risk and allowed all of the companies effectively almost risk free, to get these volumes on the market. Is does that model make sense for the IOC? Does it make sense that they continue to underpin this demand growth, which long term actually hurts the profitability and the pricing power? Yes. I think so two questions there. If I start with the second one, then go to the first and then give Steve the opportunity to think and give an even better answer. On the first one, of course, yes, the tolling structures for the investors are relatively low risk or even risk free, as you say. They're also relatively low returns. So that's very much an infrastructure investor model that people went for. But indeed, it leverages the risk for the people signing the tolling contract because this is a take or pay structure that in the current market, a few players will regret. It hasn't there's certainly been IOCs signing up to these contracts. We, of course, have the Cheniere Train 1 contract and we have our own Alba project. But there's also been a lot of utilities and more kind of trading companies in that game. And what you see at the moment is that U. S. New U. S. Projects are finding it really difficult to gather enough demand to get to FID. So you can see it's certainly a reluctance in the market to sign up. The one that got away to FID was Venture Global and we are part of the offtake there. That was a very advantaged project. Well, we could we see a lot of hesitation in the market to sign up to new U. S. Stalling structures, not necessarily because the construct is a poor one, but also more perhaps so because there are cheaper source of LNG right in the world, in East Africa, in Russia, in Qatar that from a systems perspective should come first. And you could easily imagine that the industry only needs new U. S. Supply more towards 2,030 than much earlier. So that dynamic may well play out in that way. Indeed, I mean, 2019 was an extraordinary year in terms of so if you put 4% market growth plus a degree of decline in the current base, you could see that covering 3 years of demand growth without too much trouble. I'm a bit less worried than you are about the yellow bar because the yellow bar simply means that volume goes into portfolios. It doesn't mean it's not unplaced. So if you look at 2018, LNG Canada would be in there. And of course, CoGas and CMPC are off takers there and they will simply put it into their own that's placed LNG, but it would still be yellow. So it's not the case that all the yellow here is in placed LNG. And to the extent that we take it into our portfolio, parts of that would have been sold by now. And so it's not all flexible LNG coming into the market, but parts of it will be unsold. I don't think that is necessarily problematic because these projects will take 4 to 5 years to come on stream. And the people that took it into their portfolio to the extent that it's unplaced have a bit of time to place it. So to me, that's more about injecting flexibility in the market necessarily making it long for a long time. But clearly, you can't go through too many years of FID ing 70,000,000 tons without creating at some point too much length in the market. I don't we don't expect it to happen. I think this will this was clearly a record here. This year, we expect Qatar to still come through and maybe 1 or 2 other things. So it won't be a mediocre year, 2020. But I think beyond that, the number of FIDs and the volume will fall back to normal or even below normal level, which is a bit the cyclical nature of this industry, where the trains tend to stop at the same time and then nothing comes for a while. Steve, do you have anything to add? Yes. I agree with Martin completely that it's premature to call it scary. A lot of the volume in 2019 was basically to catch up on the 2.5 year period where we had virtually no FIDs in the industry. And in some of these previous discussions last year and particularly the year before, we were calling out the opposite. We were saying unless new projects assumption soon, we will have a very significant undersupply in the market. So I think what we've seen in 2019 is the market has caught up with what's required to meet 2025 demand, which is why the previous chart or the next chart shows that pretty much a balanced market in 2025. So I think it's what happens next that will determine whether we get into a scary situation or not. Secondly, as Martin said, you know, not all of the while a lot of this equity offtake is equity offtake, there are some long term contracts sitting behind it at the other side of portfolios or people have time to put new contracts in place. But equally, some people may be quite comfortable having flexibility in their portfolio. We showed before that 30% of the growing LNG market is now sold under spot contracts. So it's not really consistent to have a market where 30% is sold spot and everything is necessarily committed under long term contracts at the same time. You need some flexibility in the business. And the third thing I would say is we face quite a different situation today compared to last time we saw the big phase of FIDs in U. S. Projects. Those FIDs were really driven by a set markets. The gas price in the U. S. Was about $5 Europe was about $10 Asia was about $15 And Asian buyers were desperate to change the dynamics of the market. So all contracts weren't locked into oil pricing and launching U. S. Exports was the way they did that. So while some of the off takers were IOCs, they often had Asian buyers sitting behind that were taking the ultimate demand. So you don't have the same pressure to change the market structure today as you did when that last wave of U. S. LNG was introduced. Okay. So we'll take one here and then we'll go on. Yes, it's Jon Rigby from UBS. Can I ask two questions? One is the difference in the U. S. And everywhere else is U. S. Everywhere else supply costs are fully built up cost from the wellhead, whereas U. S. You typically buy 3rd party gas from a very liquid market. But with that very liquid market trading at sub 2 and the futures out sub 2 or around 2 for as far as you can see, Isn't there a temptation either physically or synthetically to lock some of that supply in as you would do if you were committed to just produce the gas from a well? The second question, just to go back on the comment that you made about U. S. Export, is one of the other changes going forward well, twofold. One is that a lot of the export facilities were built on effectively brownfield sites that were conversions. We're sort of running out of those, and so the cost equation changes. And secondly, to that cost equation, were they also sort of predicated upon optimistic views about build cost and timing, which have subsequently been proven to be incorrect. And so if you were to go forward with the next giant export facility, you would probably have a very different sort of cost estimate for that, which I guess maybe limit the exports of the U. S. Being that there's a very big difference between cost of cash cost of exports and fully built up cost of export. Yes. I guess, Steve, well, a few thoughts. Whether it's wise or not to lock in Henry Hub at current futures prices, I think we shouldn't be giving advice here. But I think one of the risks you would run as an oil that you're then locked into off taking the LNG as well, which at the moment, people at least have the option turn it down if the economics are really poor. But if once you're committed to buying the gas at a certain price, then you're not sure whether you will be able to get rid of that hedge again if the market turns out to be €1.50 instead of €1.90 So it goes you lose a bit of optionality if you were to look in the LNG price. So that's something to think about if you're considering going down that road. It clearly has the difficulty with the U. S. Setup is that you essentially have to write down your tolling fee at the start of the year because you're going to pay that anyway, whatever you do in most contractual contracts. And that just makes it a much riskier construct than if you have a fully built up equity that you're into. And that I think is I'm not sure everybody that signed up to it in the years when they did fully recognize different risk reward profile of that structure. It's definitely true that the brownfields are running out. We partly control the last big one in Lake Charles, and we'll see how competitive that is as the bids come in and as the structure dries up. And that does mean, in principle, the greenfields, of course, are more expensive and more risky and cumbersome. The quotes we hear about in the market continue to sound relatively competitive compared to other U. S. Projects. The $1.90 Henry Hub isn't particularly cheap gas. It's cheap compared to the past of Henry Hub, but if you produce gas in Northern Russia or in Qatar or in East Africa, it doesn't cost $1.90 So there is Henry Hub is a relatively even at these levels, a relatively expensive start of a liquefaction project. And that at the moment is, I think, one of the reasons that this is do you want me to talk into this microphone, right? That, I think, is one of the reasons that, structurally, at the moment, there's a few projects ahead in the curve of lots of U. S. Projects going away. Yes. So if you go back to the lock in comment, that's something that's probably easier to do in theory than in practice. You can do it in practice, but there's 2 ways you could do it. You could either buy fixed price gas, in which case you're taking quite a lot of performance risk on your counterparty if Henry Hub prices did increase significantly or you could use financial products to effectively hedge the price and lock in the price. But for the volume and the time period we're talking, there will be quite a lot of cash required to manage that bigger hedge position. So it's something that we could do it, but it is not as simple as a throwaway line. Secondly, one thing you didn't mention that one of the biggest challenges that U. S. Projects face is their cost structure is incredibly transparent. So in a market where the U. S. Is competing with, you know, Qatar and Mozambique and Russia and other supply sources for a limited amount of incremental demand in the near term, you know, it's very easy for those other countries to know what the U. S. Cost structure is and how they need to price. And therefore, it becomes really important for the U. S. Projects to make sure they are absolutely at the low end of the cost curve. Okay. We'll take a question online. So We'll take the question from Roger Read with Wells Fargo. Yes. Thanks. Enjoyed the presentation. Kind of following on the cost structure question and looking at your chart that shows the decline in capacity from existing LNG facilities. I was wondering is that limited to just the underlying fields depleting or are you considering cost structure as part of that? And the reason I'm asking is, we think about so many of the historical legacy contracts being oil linked as we see those contracts come to their original ends and maybe switch to a more spot driven or hub driven pricing situation. Could that create a situation where those facilities are now uncompetitive or less competitive versus new facilities coming online? Yes. It tends to be associated with the gas supply into the facilities. LNG plants will but It may be the case that the local gas market has grown or and therefore, there's not sufficient gas in for a country to be able to meet its domestic needs and export at the same time, and therefore, there's a logical prioritization of the local gas market. Yes. And perhaps to your second point, so indeed, that's what it is here. It is not assumptions around price formulas changing. And actually, if you look at Slide 27 of our presentation, you would see that oil linked pricing continues to have a strong market share in the total of LNG term deals being concluded. It went up a bit year on year. I wouldn't see that as a trend, but you still see about half of all the volume being signed up on oil. And so it's definitely not the case that oil pricing is a thing of the past. Quite a lot of customers continue to like it and sign up to it. We'll stay in the room here and Understood. Thank you. Thank you. Yes. Bertrand, Kepler Cheuvreux. Two questions, if I may. You elaborate on LNG demand for Asia in 2020? Looks like there's a kind of double compared to 2019 level. Can you explain the moving part? And then the second question is a follow-up to Michele's question with 71,000,000 tonne of LNG being sanctioned last year, if we had this year, let's say, Nigeria, 8,000,000 and Rovuma, 15 something, we get to above 90,000,000 tonne. And I remember a slide that you put up last year saying that over 20 19, 2021, there were potentially a place for 90,000,000 tonne to be sanctioned to meet the high case demand. So that's why I may ask a question. It looks already scary to me. But then if you put Qatar on top, it looks even more scary. So can you have you changed your demand forecast? Or what has changed in this, I would say, FID scenario, 'nineteen, 'twenty, 'twenty one? Okay. So first of all, on Asian demand, we are this has a forecast growth of between 15,000,000 and 20,000,000 tonnes, and that is a combination of China, Japan and Korea and India, maybe a third from each of those three regions. As I said, if we were to recreate this data today with the coronavirus impact, it would probably be a little bit lower. But the big change between 2018, 2019 2020 is that in 2019, we saw LNG imports in Japan and Korea decline, whereas in 2020, we're expecting to see them increase again. In terms of your second question, yes, last year, we presented a chart which showed new FIDs that are required to satisfy demand in a range of in a high and a low case. The demand forecast has grown this year, and that's driven by the more aggressive coal to gas switching activity that we're seeing. But you're right that the 70,000,000 tonnes has kind of caught us up. And therefore, if you had a similar level of new FIDs this year, that would be quite hard for the market to absorb in 2026. Now the reality is that if you FID big projects, they tend to come on over a 2 or 3 year period. But I retain my view is that what we've seen doesn't put us in a scary position because the market can absorb it. Depending on what we see going forward, we may or may not find ourselves in a scarier environment. But indeed, it's going to be interesting to watch. So I'd say they I would personally see the Qatar four trains as opposed to FID, although it doesn't perhaps tick every box of what you would consider FID. I don't think the Qatar is there's any probability of them not building those 4 trains. They're deep into FEED and into EPC contracts. And as a nation, they've decided to do this. So that's why you see the dotted line on the chart. We think for all intents and purposes, that is going to happen. And therefore, indeed, that's a strong start to FID in 2020, if you accept that. Historically, we've always had long lists of promising LNG projects. And what actually made it across the line often look different. But of course, if this year plays out in a very linear fashion and everything that looks promising gets FID ed, then clearly, we're looking at a long market in the second half of twenty twenty, which we'll tell you more about next year if indeed it happens. Is there more on the line or should we say another one? No, go on. Okay. Thank you. Chris Coopman from Bank of America. Two questions, please. Just wondered, with that Henry Hub outlook at, let's say, 2 forever, how do you like your 850 breakeven that you announced for LNG Canada, despite the fact that greenfield is going to be a bit more expensive than brownfield. But it looks to me at $2 Henry Hub plus $850 looks a little high in terms of the competition you're facing from more marginal U. S. LNG exports. And the second question perhaps for Steve is, you mentioned the very high storage levels that we are witnessing here in Europe. What's your best trade in terms of winter summer spreads? Because the summer looks pretty horrible to me. So I wonder whether you can give us any color on that. Thank you. I'll do Canada. I'll let Steve explain how we get through the summer. The yes, of course, the Canada situation is not totally delinked from the U. S. Situation. So, when we talked about Canadian returns and prices, We certainly weren't counting on the Canadian gas prices being below $1 And so, if indeed the scenario plays out that North American gas prices stay as low as they are right now, that project will get a significant boost on its own upstream and remain competitive versus the U. S. That freight the advantage it has in terms of freight and upstream gas cost is, we believe, lasting. And also in today's market, if it was on stream today, we would be happily producing. So that's an important thing to note on that project and why we do believe Canadian expansion, under most circumstances, is likely to still be a competitive project as we look at it in the coming The other point I'd make is whether Henry Hub will really survive below $2 for a long time, I think, really depends on what you believe happens in the Permian because it's really driven not necessarily by dry gas production, it's being driven by gas production where gas is more of a byproduct of the liquids being produced in the Permian and needs to be evacuated at any cost. That is pushing the gas price down. And it's and I'd say, at the moment, it's very hard to call how long that situation will last. Yes. That's the summer? Well, the purpose of this event, obviously, is not to give you our best trades. We'd like to keep those to ourselves. But we can tell you a very positive story starting from the summer onwards. Between today and the summer, the market is going to continue to face challenges. We have a low price today and mild weather and high inventories and the uncertainty of Chinese demand. So the next 2 or 3 months will probably continue to be quite tough. And a lot of LNG coming on. Yes. Now we're not necessarily massively exposed to the spot price because of the way we put together our portfolio. But for the industry as a whole, yes, it's not there's probably limited further downside risk from where we are now, but it's there's not an obvious turnaround that's going to come in the next couple of weeks. Thanks. It's Lydia from Barclays. Just two questions, if I could. The first one was you talked about higher utilization of the existing stock last year. What changed what actually caused that and what changes this year? And can I just check that the downtime at Prelude isn't related to that it could force you or to just optional utilization numbers? And then secondly, just, Martin, in terms of the policy and the challenges to roll of gas and energy transition, we are seeing more and more pushback in terms of gas usage. Can you just talk about sort of how much of the demand numbers rely on policy support coming through? Yes. I'll start with the second one. Outside the U. S, for gas to displace coal, it fundamentally relies on policy, Both in Europe and without the carbon price, it's hard to see gas compete with coal. And in India and China, equally, it needs support from policy perspective. Usually, that's more air quality than CO2 inspired, but still. As long as natural gas is displacing coal, I don't think the policy support is in doubt because the advantages are obvious and the story is easy to tell. If we come into a position where it's either natural gas or renewables, then I don't think natural gas has much of a chance. Except for the sectors that cannot be electrified. And too often in these somewhat simplistic discussion that's being had on the future of energy, people believe that solar and wind will solve the issue. But significant sectors of energy demand can't be electrified. We'll continue to need a molecule in order to run. If you think about aviation, steel production, cement, petrochemicals, fertilizers, long range shipping. Now even if you believe that in the very long term, biofuels and hydrogen will do their job, in the next 25 years, those value chains will not be of a material size, even if we start really hard working hard on them. And so we believe eventually when policy meets reality, natural gas will have a significant and prominent place in those industries. But it requires continued efficacy from those who see that picture Otherwise, it might drown in a sea of what you might call ignorance. And that could be quite a risk to the energy transition if it does. So on the other question, this is not a massively significant change. So the LNG industry is now of the size that a 1% change in utilization across the whole industry is almost 4,000,000 tonnes a year, and that's all we're talking about. There's 4,000,000 tonnes above expectations. So it's hard to predict the utilization across every LNG plants in the world to the nearest percent. So no massive change. It's just a function of the timing of maintenance and other things. Prelude is shut down maintenance. It's not a price optimization. Okay. We go to the line, and then we'll come back to it anyway. And we'll hear from Jason Gabelman, Cowen. Yes, please go ahead. And one moment, please. Low cost LNG projects out there. Sorry to interrupt. You start again? Because you were on mute for a bit. Could you start again? Because we were falling in the middle of your question. Yes, sure. Can you hear me now? Yes, thank you. Yes. So there seems to be a lot of LNG projects out there waiting to be sanctioned And it seems like there are more and more that are being presented to the market. So do you see the cost curve or the LNG price that's required to sanction these projects moving lower over time to meet projected demand growth? And then the second question, just specifically on India and its LNG demand growth. It seems like it's still a big part of the story. And there have been issues, I think, with infrastructure in that country and getting high utilization rates at their regas plants. So do you think that that is a risk to the demand growth outlook over time or is the government more focused on getting the infrastructure in place to utilize those regas plants at higher levels? I think I'll start on India and then hand over to Steve. I think India is, to a large extent, an upside case. You're absolutely right to point out that infrastructure in India is a difficult issue. It requires the cooperation between various regions who tend to be think quite autonomously about infrastructure. If even half of the announced infrastructure projects in India actually are built, there is significant upside to the gas demand pictures that you've seen in this presentation. There is occasional and sometimes somewhat anecdotal investment in infrastructure in India, but there is also some real investment going on in building low pressure pipeline grids into cities and linking significant regions. Certainly, the bit of the Indian gas system that we are directly connected through Hazira is currently operating at absolutely full capacity, and we're not having any infrastructure constraints in getting the gas away. But I think in the infrastructure, we're not counting on much happening in this outlook. So, to a large extent, there's an upside to this scenario rather than a downside. Yes. So to build on the India story, the government could clearly do help to build more infrastructure, but there has been quite a bit of new import capacity come on stream in the last year or due to come on stream this year. And as Martin says, we've seen record throughput through our own Indian LNG import terminal this year. On the cost structure, absolutely, there are a lot of competing projects in the market today. The market doesn't need all of them, And therefore, there is massive pressure to on any one project to be competitive and to be able to demonstrate it's competitive to move forward. Will the cost structure continue to move down? The most transparent way to look at the costs of LNG projects is the cost of liquefaction on the U. S. Export projects. And over the last 5 years or so, we have seen a continued reduction in that cost. Okay. Thank you. I just wanted to ask about projects or contract sanctity. So you talked about record FIDs, record low gas prices. India is out there asking already some other players to renegotiate. So are you given all that's happened in 2019, are you still confident in contracts sanctity across your portfolio? Yes? Yes. The bigger the spread between term prices and spot prices, the more tension you get that you have to deal with because it becomes harder and harder for the term buyers to be able to manage that situation. But ultimately, the industry has a tremendous track record of long term contracts being performed, and we expect that to continue. Hi, thanks. Biraj, RBC. One of the things you mentioned, Steve, was the market is becoming more transparent. And I guess the futures market and the products are getting more complex. But I guess having 20% market share in a very opaque market as a trader sounds quite nice. So what does that mean for you over time? Does it is it good or bad having the ability to do more or having more competition? That would be the first question. And the second one, kind of related to that, but you recently signed a coal linked LNG deal. I guess that's just to compete is that a specific deal to compete with the fuel in that country, competing fuel? Or is that something that we will see more of over time? Yes. So first of all, I think having 20% market share is an advantage regardless of market conditions or circumstances. Transparency brings pluses and minuses for our business. But one of the benefits that we're seeing is the increased ability we have to use financial products to monetize our optionality or our price insights. So in the past, if we had a view on the market, we would have to struggle our physical portfolio in such a way to take advantage of our pricing view, whereas today, we're able to delink our physical position and our pricing exposure much more. So if we have a pricing view, which would make us want to be short, JKN pricing, for example, we don't need to be physically short. We can retain physical length, retain the optionality of having length and the reliability to supply our customers and be market structure. In terms of the Cold Linked LNG contract, that was a specific solution to a specific problem. We had a customer who had announced that they were going to build a coal fired power plant but didn't really want to. And by signing a coal index LNG contract, it gave them a mechanism to cancel that project and then be able to claim to their stakeholders that they had got the benefits of a coal indexation without necessarily having the downside of a coal in of a coal fired power plant. So when you look at a coal plant versus a gas plant, coal is typically cheaper than LNG, but the power plant is expensive and the carbon tax is more expensive. So we were able to create a commercial structure where we had something to reflect the coal pricing, something to reflect the savings on the capacity cost of the plant, something to reflect the savings on the CO2. And then there were other things in the contract which were attractive to Shell. And for us to maximize the value of our business, the more different price inputs and outputs we have into our portfolio and the flexibility we have, that's what allows us to create a lot of value. So this was a really good example of a solution that helped the customer by giving them a solution to their stakeholder challenges, and it helps us by diversifying the price optionality in our portfolio. Will there be more or not? We haven't had tons of people knocking on our door wanting coal index contracts, but it's consistent with the chart that we showed where we are seeing more different types of indexation in the market. And again, that's good for us. If we can give our customers something that they want to meet their challenges or their needs and it creates additional value for our portfolio, then that's a great outcome. Hi. It's Peter Low from Redburn. Thanks for taking my question. I think you've said that over 70% of your volumes are sort of long term contacts today. Is your intention to maintain that level of coverage going forward over the next decade? Because obviously, we see you is the ultimate intention to kind of lay those volumes off and sign new contracts as you move through the next 10 years? Yes. We definitely, the intent is to continue to have a long term business, both on the supply side and on the demand side. We believe that gives the kind of resilience to our P and L and cash flow statement that you will recognize from looking at our quarterly results for the last 10 years. And that's the kind of resilience that we want to bring also deliver to the company's financial framework. So we would intend to continue to be predominantly sold on a long term basis whatever we buy or own on a long term basis. And we see sufficient opportunities in the market, whether it's LNG to transport, whether it's the kind of deals we did in Hong Kong or in Ghana last year where we get long term access to markets, in both cases, exclusive access to markets where we can build long term positions that are, A, resilient B, hopefully, exclusive and C, premium positions. And that is the ideal way of building out the portfolio. We will always want to keep a bit of volume spot, but it is not the it's not a preferred riskreward picture of our portfolio. It's Colin Smith for Panu Gordon. Just building on Lydia's question about the energy transition, I think you mentioned earlier about the need to find a pathway, which I think was more to do with gas, about putting biogas in CCS related to gas rather than LNG. But just in connection with LNG itself, obviously, there are questions around the amount of greenhouse gas emissions associated with the whole process of producing, converting and selling to customers. And I was wondering how you actually approach that in the way you think about it. And I'm thinking here also about feedstock conditioning, where you've got CO2 potential CO2 content in the feedstock and whether or not there's any practical examples where customers are looking much more carefully at where they source LNG for the potential greenhouse gas issues that might be associated with a particular supply source? Thank you. Yes. Thanks. It's a crucial question, and I believe that agenda will become more and more prevalent as time goes by. At the moment, we have some examples at the positive end where customers are willing to pay us extra in order for their LNG cargoes to be CO2 offset. So I think Steve has now already sold 3 cargoes in the last 6 months, 2 customers that are fully carbon offset using nature based generated nature generated carbon credits that we buy from reforestation and avoided deforestation projects. And so you're starting to see and for example in the example of Tokyo Gas, they go on to market that gas in Japan as carbon offset gas and attracting a premium for it or at least having a good marketing story around it. So I think that business is starting up, but more on the carbon offset side rather than customers saying, show to me what the excess carbon content well to tank well to the tank that the customer's tank is. But I'm convinced that, that will, over time, become a feature of the business. The way we look at it, we set performance standards for the upstream CO2 component of the gas, which is both in terms of reservoir the CO2 in the reservoir as a CO2 in the upstream operation itself. We set a performance standard for the midstream and one for shipping. And essentially, if you add all that up, then you get very, very CO2 advantaged LNG in the tank of the customer that would be at the left hand of the curve when customers look at that situation. Now that's for new LNG. Clearly, there will be legacy projects in our portfolio that have a higher CO2 footprint and over time could be exposed to a world where LNG customers insist on looking through the chain and insist on certain CO2 footprints. We also reflected in our economics. So we charge our economics with an expected CO2 price, not only tomorrow, but also 10, 20, 30 years out. And we burn the economics with that picture. But eventually, I do believe that a gas market will emerge that has certain tranches of CO2 pricing or CO2 products in it. And we are determined to play in the premium end of that if we can. It is also possible that it will emerge in domestic markets, particularly such as the one the U. S. A, where clearly there's a lot of differentiation in terms of the CO2 content of gas. So it's an active agenda. For our new projects. We set significant targets. But we also worked actively with commercial constructs, such as the carbon offsetting, to start to create a market that is carbon dependent and carbon dependent. So one other example is, obviously, you have the ability to turn biogas into bio LNG, and we've now announced the construction of a small scale liquefaction plant in Germany where we will do that. We'll produce Bio LNG and we'll develop a network of Bio LNG fueling sites for trucking across Germany. Okay. Thank you very much. I think we're at the end of the allocated time now. If there are further questions, either online or here in the room, you can always come up directly to us, to Investor Relations, and they will deal with them. And thank you very much for your attention, both online and here in the room in London. Okay? Thanks a lot. Bye.