Shell plc (SHEL) Earnings Call Transcript

Good day, and welcome to the Shell 2020 LNG Outlook hosted by Maarten Wetselaar, Integrated Gas and New Energies Director; and Steve Hill, EVP for Shell Energy. [Operator Instructions] As a reminder, today's call is being recorded. And now Tjerk Huysinga, EVP for Investor Relations, will give a short introduction before handing over to our first speaker, Maarten Wetselaar. Please go ahead.

Great. Thank you very much for joining us here. We are here in The Hague. Indeed, this is Tjerk Huysinga, I'm the -- I'm leading IR. It's a great honor that we are here, together here again. This is the fourth edition of the LNG Outlook. Indeed, as you've just heard, we'll have Maarten Wetselaar, the Director of Shell Integrated Gas and New Energies; 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&A. So let me hand it over now to Maarten. Thanks a lot.

Thanks, Tjerk. And for those who got confused, we're actually in London, not in The Hague. But other than that, I completely stand behind Tjerk's announcement. Yes. 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. Fourth LNG Outlook, it's great to see you this morning, with the media 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 turning you -- what you're about to hear, and -- which is 3 key messages. One 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 this is 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 supply and demand side and how it played out in terms of the 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 million tonnes of LNG showing real -- really strong confidence in the future of this business, which we underwrite. We will 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. I'd say on the macro side, we continue to see this trend of -- a trend of growing population. The world added 750 million inhabitants over the last 10 years, significant population growth, and we see us -- we see the world having well over 10 billion people by -- well over 9 billion people by 2050. And of course, as a -- they will all strive for prosperity, and we'll go through the -- 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 the 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. And 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 Paris hasn't been broken in the last 10 years, and will need to be broken going forward if those Paris commitments are going to be 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 million 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 another very significant driver of gas uptake, particularly at the expense of coal. This year, you will see that this analysis goes until 2040. So far, we always used until 2035 as the long-term reference here, but of course, as time has gone by, for the fourth 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% 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 is 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 we -- where the 2040 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 2040, and gas is gaining market share in 2019 to 2040. 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 2040. You see in both cases, on the right of that, in the case of India, to the far right of that, you see the 2030 target from the government. And so there's real tension between what is projected here and what the government targets are. And even if the gas market in these 2 countries ends up halfway in between, that will be difficult to supply in the 2020s if that 2030 target is halfway met. So we do believe that this is upside rather than downside in terms of increasing 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 million tonnes 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 this 32, 7 were -- made that phase-out commitment last year and amongst them are 3 material ones. Germany, which is the largest coal user in Europe; Mexico, which is the largest coal 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 capacity by fuel is distributed across the main markets when it comes to the orange pictures. The blue, the light blue depicts the current gas-fired power capacity in these markets. And that squares give the endpoint in 2040 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 a 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 used at home, killed 3.8 million 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 Morbi in Gujarat in India, where we have an LNG regasification terminal. Morbi is a major ceramics production cluster 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 and PM10 and SO2 concentrations were in 2017 in Morbi. 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 '19 and October '19, the industrial sector in Morbi tripled its gas demand, and the industry was able to respond; and how this had an impact on air quality in Morbi, which is the red bars in the left-hand graph. The 2.5 dropping to well below 100, 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 the example of South Australia, which is a market that's very progressive, about -- just under 60% gas, just under 40% renewables. So very much a market that is -- in that sense, there's 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 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'd 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% and 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 the 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 burnt 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 -- government and people can commit to gas without worrying about overpaying across the cycles. These are 3 things that the industry should have in its own power and it should definitely be able to address ahead of the curve. But we also need governments like the government of Morbi 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 or CO2 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 will 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 demand, 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, where natural gas will be a long-term play. Over time, biofuels and hydrogen, we know that come into that mix. But if we phase out natural gas or if we constrain natural gas too early, we will actually look in coal and other more source for too long, and that will be -- go at the expense of progress on climate change. You can see that 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 the 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 that down by region, you can see that Asia is still the major market, taking 3/4 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 2040 to be double the LNG demand that we see today, about 700 million tonnes. I'll hand over to Steve to go deeper into 2019.

Thank you, Maarten, and 2019 was quite an interesting year for the LNG industry. This is the fourth time we've done the outlook, as you heard, and it's the fourth time we've described 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 million 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 million tonnes split between Australia, the U.S. and Russia, and actually, what we saw was the supply growth being a little bit higher than forecast at the start of the year. And that wasn't driven by the new projects coming onstream, rather the existing facilities operating at a higher throughput than expectation. And then the charts on the right shows -- the yellow box is the range of forecast for where that growth of LNG would be absorbed by the market. So we set about 10 million tonnes into Europe and between 20 million or 30 million tonnes -- sorry, about 10 million tonnes into Asia and about a growth of between 20 million and 30 million 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, in orange; compared to the expectation at the start of the year, the gray bars behind. And what we saw was that the sixth -- 5 of the 6 biggest countries for LNG growth are 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 charts, 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 effects of mild weather. And then you have -- 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 -- at 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. That -- 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 2 charts on this side -- on the right-hand side of this chart. When you look at the demand side, that increased gas demand in Europe came from a combination of a build in 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 2 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 via 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 has -- which resulted in actually more gas being consumed than coal in European power generation for the first time ever. So part 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 at 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 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, increase 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 production actually declined during the year. And therefore, when you look at the countries that import LNG on the right-hand side, we saw growth in all of these countries, 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 markets. 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 2 things meant we saw a reduction in LNG imports into these 2 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 2016 and the markets to which the volumes have gone. So initially, 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 1.5 years as the 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 market over the recent few months, combined with a very mild winter in both Europe and Asia, reducing demand. And now most recently, the impacts of the 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 to Asia continued to increase. And we think this demonstrates the robustness and resilience and flexibility of the LNG market, that despite these geopolitical issues that we see from time to time, the market is very effective at rebalancing and cargo is being lifted and customers are 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 being 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. got quite small, 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 market, 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 continued 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 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 amounts of LNG sold under long-term contracts in 2019 versus '18, 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've ever seen before. In fact, 2019 was the first 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 million 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 it today, we'd probably see a slightly lower number for Asia and either Europe adjusted upwards to offset or potentially shut-ins from -- or turndown 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 into 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 first 3 of those 4 years, we saw the market pretty much keeping up with supply growth and most of that new LNG being absorbed in the Asian market. 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-2020 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 nonliquid markets, absorb all the LNG supply and a tightening or a rebalancing of LNG markets. 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 2015 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 were made in 2019 is compared to that 71 million 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 projects sold LNG to customers and the area showed in the yellow is LNG, which is offtaken 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's a sign of the flexibility and the changes in the commercial structures of the market 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 amounts 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 4 trains of the proposed Qatar 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. The area in light green above that are markets where they can absorb LNG, but the LNG 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 necessarily supplying growth in gas demand, but more so replacing declining domestic 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 bunkering fuel to 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 containerships. So the ships that are already in operation or under construction will have a combined LNG demand of about 2.5 million tonnes a year. So the equivalent of a small LNG importing country. However, the forecasts are that the LNG demand for this sector will continue to grow much more rapidly. The IEA forecast for 2040 is 37 million 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 Paris-Siberia pipeline, which is starting up at the moment and still bring in incremental LNG on top of that? And therefore, rather than just showing the demand expectation out to 2040, we've broken it into 2 periods: between now and 2025, which is the period over which the power of Siberia is expected 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 Maarten 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 2040 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 policies 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 of 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 the team will point it 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 NBP 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 that 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 in -- back in a world where LNG demand will be growing faster than LNG supply and LNG being pulled 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 to 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.

[ In the room. There's one ].

It's Michele Della Vigna from Goldman. I had a question for you, Maarten. 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, with so 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 '19 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 happen because the IOCs underpinned that risk and allowed all of the companies effectively almost risk-free to get these volumes on the market. Is it -- 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 2 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 return, 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, at the Cheniere Train 1 contract, and we have our own Elba 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 demands to get to FID. So you can see, 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 do -- we see a lot of hesitation in the market to sign up to new U.S. tolling structures. Not necessarily because the concert is a poor one, but also more perhaps so because there are cheaper source of LNG elsewhere in the world, in East Africa, in Russia, in Qatar, that from a systems perspective, should come first. And so you could easily imagine that the industry only needs new U.S. supply more towards 2030 than much earlier so the 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's 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, that volume goes into portfolios. It doesn't mean it's unplaced. So if you look at 2018, LNG Canada would be in there. And of course, KOGAS and CNPC are offtakers 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 at all. The yellow here is in place to 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 onstream. And the people that took it into their portfolio, to the extent that it's in place, have a bit of time to place it. So to me, that's more about injecting flexibility in the market than necessarily making it long -- for a long time. But clearly, you can't go through too many years of FID and 70 million tonnes 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 year. This year, we expect Qatar to still come through in maybe 1 or 2 other things. So it won't be a mediocre year, 2020. But I think beyond that, the number of FIDs in the volume will fall back to normal or even below normal level, which is a bit the cyclical nature of this industry, and where the trends 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 Maarten 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 are sanctioned 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 Maarten said, not all of the -- while a lot of this equity offtake is equity offtake, there are some long-term contracts sitting behind it to 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 in the 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 of market circumstances where you had very high price spreads between different 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 offtakers 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.

Sure. Okay. So we'll take one here, and then we'll go online.

It's Jon Rigby from UBS. Can I ask 2 questions? One is the difference between 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 third-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. exports, 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. And 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 out of the U.S. being that there's a very big difference between cost of -- cash cost of export and fully built-up cost of export.

Yes. I guess -- well, a few thoughts. Whether you -- whether it's wise or not to look 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 -- that you're then locked into offtaking the LNG as well, which at the moment, people at least have the option to turn it down if the economics are really poor. But if -- once you're committed to the -- to buying the gas at a certain price and 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. And 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 terms of automization in most contractual constructs. And that just makes it a much riskier construct than if you have a fully built-up equity position that you're into. And then I think it's -- I'm not sure everybody that signed up to it in the years when they did fully recognize the different risk/reward profile of that structure. It's definitely true that the brownfields are running out. We partly controlled 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 more cumbersome. The quotes we hear about in the market continue to sound relatively competitive compared to other U.S. projects. The problem or the challenge really is that even at $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 -- that -- you want me to talk into this microphone, right?

Yes, yes, yes.

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. Do you want to add?

Yes. So if we 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 for 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 that there will be quite a lot of cash required to manage that bigger hedge position. So it's something -- we could do it, but it is not as simple as a throwaway line. Secondly, one thing you didn't mention that's 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 Qatar and Mozambique and Russia and other supply sources for a limited amount of incremental demand in the near term, 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 please go ahead. What was the first in the queue?

We'll take the question from Roger Read with Wells Fargo.

Yes. 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 typically operate for quite a long time, but it's not necessarily solely to do with depletion of gas supply. It may be the case that the local gas market has grown or -- and therefore, there's not sufficient gas for a country to be able to meet its domestic needs and exports 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 formula is changing. And actually, if you look at Slide 27 of our presentation, you will 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...

Yes. Bert Hodee, Kepler Cheuvreux. Two questions, if I may. Can 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 million tonnes of LNG being sanctioned last year. If we had this year, let's say, Nigeria, 8 million and Rovuma, 15-something million, we get to above 90 million. And I remember a slide that you put up last year, saying that over 2019, '21, there were potentially a place for 90 million tonnes to be sanctioned to meet the [ 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 '19, '20, '21?

Okay. So first of all on Asian demand, we are -- this has a forecast growth of between 15 million and 20 million tonnes. And that is a combination of China, Japan and Korea and India, maybe 1/3 from each of those 3 regions. As I said, if we were to re-create this data today with the coronavirus impact, it would probably be a little bit -- a bit lower. But the big change between 2019 and 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 hot -- 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 million 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 your 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 scary environment.

But indeed, it's going to be interesting to watch. I'd say that I would personally see the Qatar 4 trains as opposed to FID, although it doesn't perhaps tick every box of what you would consider FID. I don't think that Qatar is -- there's any probability of them not building those 4 trains. And they're deep into FID and into EPC contracts. And as a nation, they have 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 a long list 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 the 2020s, which we'll tell you more about next year if indeed it happens. Is there more on the line or shall we stay in the room?

We have more. [ Keep going ].

Okay.

Chris?

Chris Kuplent 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 $8.50 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 $8.50 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.

Okay. 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 advantages hasn't [ turned the freight ] and upstream gas cost is, we believe, lasting. And also in today's market, if it was onstream today, we would be happily producing. So that's an important thing to note on that project and why we do believe that Canadian expansion under most circumstances is likely to still be a competitive project as we look at it in the coming years. The other point I made -- I'd make is whether Henry Hub already survived below $2 for a long time, I think it 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 it needs to be evacuated at any cost. So that is pushing the gas price down. And it's -- and I'd tell you, at the moment, it's very hard to call how long that situation will last.

Yes. That's...

How do we get through the summer?