Good day, welcome to the Shell 2020 LNG Outlook, hosted by Maarten Wetselaar , Integrated Gas and New Energies Director, and Steve Hill, EVP for Shell Energy. There will be a presentation followed by a Q&A session. If you have a question, please press star one. If you would like to be removed from the queue, please press star two. As a reminder, today's call is being recorded. Now, Tjerk Huysinga , EVP for Investor Relations, will give a short introduction before handing over to our first speaker, Maarten Wetselaar. Please go ahead.
Okay. 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 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. Let me hand it over now to Maarten. Thanks a lot.
Thanks, Tjerk . For those who got confused, we're actually in London, not in The Hague. Other than that, I completely stand behind Tjerk's announcement.
In The Hague.
Yes.
Always in The Hague.
We have a recording. 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 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. Then we'll move on to telling you what you're about to hear, which is three 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. You will see us argue that that 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. 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 on more than 70 million tons of LNG, showing really strong confidence in the future of this business, which we underwrite. 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. On the macro side, we continue to see a trend of growing population. The world added 750 million inhabitants over the last 10 years, significant population growth.
We see as.. We see the world having well over 10 billion people by 2050-- well over 9 billion people by 2050. Of course, they will all strive for prosperity, and many of them will go through the middle classes cycle where energy usage per capita goes up a lot. Thirdly, there is 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 you can see the potential for further urbanization. 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. 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. What you can also see on the top right-hand side is that has remained strongly correlated with the CC2— CO2 footprint of the energy system that grew by about 1.4% a year, every year. Which means 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 replaces coal in the energy mix. Air quality remains a very significant issue. On the bottom right, you see seven very large cities in the developing world. Together, they are the home to 145 million people.
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. 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 2040. Far, we always used 2035 as the long-term reference year. Of course, as time has gone by, for the fourth year, we think it's useful to go out that far. 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.
It's 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 this analysis projects a decrease in coal. -1 0% over the period, where we see coal actually decreasing in absolute terms in the energy mix in the world. 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 a number of very material energy markets.
The way this graph works, where the arrow starts is the 2019 market share, and the pointy end of the arrow is where the 2040 market share is projected to be. There's a few takeaways from this picture. One is that across the four markets and globally, coal is losing market share 2019 to 2040, and gas is gaining market share 2019 to 2040. The trend that is expressed on the left is illustrated here. What is also illustrated is the further potential. 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. There's real tension between what is projected here and what the government targets are.
Even if their gas market in these two countries ends up halfway in between, that will be difficult to supply in the 2020s if that 2030 target is halfway met. We do believe that this is upside rather than downside in terms of increase in penetration. What you see in the IEA two 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. Both are opportunities, of course, to start driving further CO2 reductions going forward.
You see on the middle side here that coal-to-gas switching over the last decades has already saved cumulatively 600 million tons of CO2 compared to the starting point in 2010. That's equivalent to more than half of the emissions from South America for a full year. So, 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. That is significant, but it's particularly significant because it's mostly the result of policy. We now have 32 countries in the world with coal phase out commitments. And last year, seven new ones. Of these 32, seven made that phase out commitment last year.
Amongst them are three 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 eight 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 light blue depicts the current gas-fired power capacity in these markets, and then the 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, 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, then the use of coal and other solids, mostly wood, in the household and light commercial sectors in the medium graph. You'll see just how much this selection of countries overlaps with the Air Quality Index on the right in 2018.
It's worth pointing out that the resulting often indoor air pollution from coal use at home killed 3.8 million people in 2016, according to the World Health Organization. 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 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 Morbi.
The Green Tribunal intervened and banned the use of solid fuel gasification, and all coal gasifiers were closed within a period of 12 months. You can see in 2019 how between March 2019 and October 2019, 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 zero, 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. 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 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. On the right-hand side, you see an example of South Australia, which is a market. It's very progressive, about just under 60% gas, just under 40% renewables.
It's very much a market that is, in that sense, there's a mix already further along the transition than most. 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, a 100-MW 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. Many more of these batteries will have to be constructed before this will start to play a meaningful role. 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% and 55%. 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. That orange bar there could be almost zero if the industry really manages emissions well. It is certainly our intent in Shell to be as close to zero as possible.
We've put a 0.2% target out to be met by 2025. We're also 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 zero as possible. 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. 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. It will also need CCS to grow up, to scale up and become a major factor particularly where gas is burnt for industry or for power.
Decarbonizing gas, taking care of the methane emissions, and of course, making sure that affordability is never at risk, that actually 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. 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. 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. And for those of you who know about the energy system know that molecules are a very important part of delivering energy, particularly to hard-to-decarbonize sectors that cannot be electrified. 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 sorts of energy demands such as steel making, petrochemicals, cement, fertilizers, aviation, shipping. There's quite a number of them 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 will no doubt come into that mix. If we phase out natural gas or if we constrain natural gas too early, we will actually lock in coal and other more source for too long, and that will go 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. 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 energy. That will kind of double the energy 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 three quarters of that growth going into Asia in that period. 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. 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 tons. I hand over to Steve to go deeper into 2019.
Thank you, Maarten. 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. 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 tons, so 12.5%. This chart takes us back to what we were looking at this time last year. We were predicting growth in the 30 something million tons split between Australia, the U.S., and Russia. 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 on stream, rather the existing facilities operating at a higher throughput than expectation. The chart on the right shows, the yellow box is the range of forecasts for where that growth of LNG would be absorbed by the market. We said about 10 million tons into Asia and about a growth of between 20 and 30 million tons would come to Europe. 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. 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. What we saw was that five of the six 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.
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. 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. Looking 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.
Those LNG imports came from a combination of pipeline and LNG, where over the last few years, LNG had taken a disproportionate share of that growth. In 2019, LNG accounted for 50% of the growth in overall Chinese gas demand. When we look at Europe, this is the real story of how the LNG market balanced in 2019. The first chart here shows how the market balanced on a supply side, on a demand side. The gas demand in Europe in 2018 was about 500 BCM, and that increased to about 530 BCM in 2019. The growth in LNG supply was much bigger than the growth in overall gas demand. 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 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. 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.
Those two prices will create a range of prices at which gas is competitive versus coal in the power mix. 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. Effectively, that acted as a floor for gas prices in Europe. 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. That can be seen in the middle chart.
In 2019, we saw an extra 13% gas-fired generation and a reduction of 16% in coal-fired generation, which resulted in actually more gas being consumed than coal in European power generation for the first time ever. Part of the growth in power demand and gas demand in Europe was this coal-to-gas switching, and the other big factor was an increase in gas inventory. The chart on the right shows the gas storage level in Europe at the end of each year for the last five years. As you see, there was a big increase at the end of 2019. This was driven by two factors. First of all, 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 one degree temperature versus the seasonal norm is equivalent to about five BCM of gas demand. So that two BCM would have reduced gas demand in Europe by 10 BCM, and therefore 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 a growth in gas demand in all sectors in this region, but the dominant growth came in the industrial sector.
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. 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. 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.
That reduced the demand for LNG in the power sector. Again, if you look at the middle chart, you will see the average temperatures in Japan and Korea over the last five winters. 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. The combination of those two things meant we saw a reduction in LNG imports into these two countries of 7%. I will 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 startup of exports in 2016, and the markets to which the volumes have gone. Initially, a lot of volumes stayed in the Americas, in Mexico or South America.
As U.S. volumes ramped up, we saw a big increase in U.S. deliveries into Asia. 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. 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. 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.
That 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 really explains the previous China story, which was all around the U.S. trade war and tariffs. As U.S. deliveries to Asia started to ramp up, those deliveries were split across China, Japan, and Korea. 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. 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 cargos 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. 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. When the market is tight, we tend to see the LNG price at the top of that range. The oil price tends to act as a ceiling because above that, then you have various fuel switching options come into play.
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. 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 continue to see developments in how spot LNG is traded, both in the physical market and on the futures markets. The actual trading of spot LNG is becoming more transparent. 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'd 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. 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. We'd expect maybe 20 million tons 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, 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 turn down of LNG projects to balance. 2020 is a year of transition for the market. 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. 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. We saw three years of strong growth and then a year of particularly large LNG supply growth over the last four years.
For the first three of those four years, we saw the market pretty much keeping up with supply growth and most of 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. 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 three years.
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. 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 market in the coming years. The first chart here shows the amount of LNG that's been sanctioned each year for the past decade. During the 2011 to 2015 period, we saw a lot of LNG that was sanctioned, which the market has just finished absorbing. What stands out is how high the amount of FIDs that was made in 2019 is compared to that. 71 million tons of production capacity is a record for LNG FIDs by a long way.
The other thing that this chart shows is how these new projects were structured, in particular, how the LNG was marketed. The area in red is where the project sold LNG to its customers, the area shown in yellow is LNG, which is offtaken by equity participants in the project. Obviously, you see the equity offtake in 2018, 2019 being much higher than in earlier sanctions. 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. We also think it is 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. The right-hand chart here shows who are the equity offtakers.
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 [audio distortion] Petroleum, or downstream NOCs like CNPC in China. When we look at the future supply-demand balance based on all those FIDs, you end up with the left-hand chart here. The area in red is the LNG that is in operation today. 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.
We have a little dashed line above that, which is what the volume under construction would look like if you assume the first four trains of the proposed Qatar expansion move ahead. The gray range is a range of forecasts of long-term LNG demand. This has also increased compared to last year, but this is a range of four different forecasts from four consultants listed below. Three of which are pretty much bunched together at the top of the range, and one is at the bottom of the range. 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. The right-hand chart here shows where that demand growth is expected to come from.
We haven't characterized markets by geography, rather by the type of markets. 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. This is countries like China, which have provided most of the growth in demand for the LNG industry over the past few years. Most of the growth going forward is at the area shown in dark green. These are countries where LNG is not necessarily supplying growth in gas demand, but more so replacing declining domestic gas production. Supplying LNG into existing gas infrastructure to meet the demand for existing gas customers.
Removing many of the infrastructure and investment barriers for new gas markets. Then, as you see at the top, we expect LNG as a bunkering fuel to become a material source of demand over time. Digging into bunkering in a bit more detail, there's now almost 400 LNG-fueled ships in operation or on order. 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. The ships that are already in operation or under construction will have a combined LNG demand of about 2.5 million tons a year. The equivalent of a small LNG imported 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 tons, 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 bring in incremental LNG on top of that. Rather than just showing their demand expectation out to 2040, we've broken it into two 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.
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. As Maarten mentioned earlier, the key markets for the growth in Asian LNG demand are South Asia and in particular, Southeast Asia. This chart shows the expected demand growth by many of the key countries in these regions. India, Bangladesh, and Pakistan representing most of the growth in South Asia. Indonesia, Malaysia, Thailand, and Vietnam representing most of the growth in Southeast Asia. As you see in both of these scenarios, LNG is both replacing declining domestic gas production and providing incremental gas supply for gas demand growth.
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. Some countries are pretty well-placed. In others, there is significant infrastructure still required to be developed. 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. 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 of uncertainty around whether that would be possible at the start of the year. That was particularly driven by the flexibility of the European gas market. 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 three to four years. I'll stop there and we will welcome questions.
We'll start in the room, I think, and there will be also some questions potentially coming in online. If they do, the team 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. That required relatively low pricing. Would you expect that we would continue to see TTF and NBP pricing essentially being set by the Henry Hub level? Just as a follow-up to that, the pricing level was essentially excuse me, being pushed down to variable cost of bringing Henry Hub into Europe. Should we think about Henry Hub plus shipping and regasification as probably a floor level for European pricing moving forward?
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. 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.
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 pulled out of Europe again. That will, we think, help the European pricing structure. In terms of that pricing dynamic that you described, that is pretty much where we are today if you look at the forward curves. 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.
Well, Russell.
Thank you. 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 three 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. What I was wondering is, how does this change your appetite to sanction new LNG projects? Also on the side, when I look at the oversupplied market at the end of 2019 and the beginning of this year, one of the big reasons for that was the extraordinary growth in U.S. export.
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. Does that model make sense for the IOCs? Does it make sense that they continue to underpin this demand growth, which long term actually hurts the profitability and the pricing power?
Yeah. 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 investor are relatively low risk or even risk-free, as you say. They're also relatively low return. That's very much an infrastructure investor model that people went for. 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. There's certainly been IOCs signing up to these contracts. We of course have the Cheniere Train 1 contract, and we have our own Elba project. There's also been a lot of utilities and more kind of trading companies in that game.
What you see at the moment is that new U.S. projects are finding it really difficult to gather enough demand to get to FID. 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. We see a lot of hesitation in the market to sign up to new U.S. tolling structures, not necessarily because the construct is a poor one, but 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. You could easily imagine that the industry only needs new U.S. supply more towards 2030 than much earlier. That dynamic may well play out in that way.
Indeed, 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 three 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 not unplaced. If you look at 2018, LNG Canada would be in there. And of course, KOGAS and CNPC are off-takers there, and they will simply put it into their own, that's placed LNG, but it would still be yellow. It's not the case that all the yellow here is unplaced LNG, and to the extent that we take it into our portfolio, parts of it would have been sold by now.
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 four to five years to come on stream. The people that took it into their portfolio, to the extent that it's unplaced, have a bit of time to place it. To me, that's more about injecting flexibility in the market than necessarily making it long for a long time. Clearly, you can't go through too many years of FID-ing 70 million tons without creating, at some point, too much length in the market. We don't expect it to happen. I think this was clearly a record year. This year we expect Qatar to still come through and maybe one or two other things. It won't be a mediocre year, 2020.
I think beyond that, the number of FIDs and the volume will fall back to a 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?
Yeah. 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. In some of these previous discussions that 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. I think it's what happens next that will determine whether we get into a scary situation or not.
Secondly, as Maarten said, 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. 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. 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. 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. Asian buyers were desperate to change the dynamics of the market so all contracts weren't locked into oil pricing, launching U.S. exports was the way they did that. While some of the offtakers were IOCs, they often had Asian buyers sitting behind that were taking the ultimate demand. 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. We'll take one here, and then we go left.
Yes. Jon Rigby from UBS. Can I ask two questions? One is, the difference between the U.S. and everywhere else is everywhere else supply costs are a fully built up cost from the wellhead, whereas U.S., you typically buy third party gas from a very liquid market. With that very liquid market trading at sub- two and the future's out sub- two or around two 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, and we're sort of running out of those, and so the cost equation changes. 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? 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. There's a very big difference between cash cost of export and fully built up cost of export.
I guess, 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. I think one of the risks you would run is that you're then locked into off-taking the LNG as well, which at the moment, people at least have the option to turn it down if the economics are really poor. If once you're committed to buying the gas at a certain price, then you're not sure whether you'll be able to get rid of that hedge again, if the market turns out to be $1.50 instead of 1.90. You lose a bit of optionality if you were to lock in the LNG price. That's something to think about if you're considering going down that road.
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 optimization in most contractual constructs. That just makes it a much riskier construct than if you have a fully built up equity position there that you're into. That I think is, I'm not sure everybody that signed up to it in the years when they did fully recognized the 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. 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. Henry Hub, even at these levels, are a relatively expensive start of a liquefaction project. Do you want me talking to this microphone?
Yes.
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. Do you want to add?
Yeah. 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 two 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. For the volume and the time period we're talking, there'll be quite a lot of cash required to manage that big a hedge position. 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's one of the biggest challenges that U.S. projects face is their cost structure is incredibly transparent.
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. 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. Please go ahead. That was the first in the queue.
We'll take the question from Roger Read. Go ahead 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? 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?
It tends to be associated with the gas supply into the facilities. LNG plants will typically operate for quite a long time. It's not necessarily solely to do with depletion of gas supply. It may be the case that the local gas market has grown. Therefore, there's not sufficient gas for a country to be able to meet its domestic needs and exports at the same time. Therefore, there's a logical prioritization of the local gas market.
Yeah. Perhaps to your second point. Indeed, that's what it is here. It is not assumptions around price formulas changing. Actually, if you look at slide 27 of our presentation, you would see that oil link 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. 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.
Understood. Thank you.
Thank you.
Yes. Bert Audet, 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? The second question is a follow-up to Michele's question. With 71 million tons of LNG being sanctioned last year, if we had this year, let's say Nigeria, 8 million and Rovuma, 15 million something, we get to above 90 million tons. I remember a slide that you put up last year saying that over 2019, 2021, there were potentially a place for 90 million tons to be sanctioned to meet the high case demand. That's why I may ask a question. It looks already scary to me, but if you put Qatar on top, it looks even more scary.
Have you changed your demand forecast or what has changed in this, I would say, FID scenario 2019, 2020, 2021?
First of all, on Asian demand, this has a forecast growth of between 15 and 20 million tons, 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. The big change between 2020, 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, last year we presented a chart which showed new FIDs that are required to satisfy demand in a range of 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. You're right that the 70 million tons 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. The reality is that if you FID big projects, they tend to come on over a two or three-year period. 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.
Indeed, it's going to be interesting to watch, I'd say, I would personally see the Qatar four trains as post FID, although it doesn't perhaps tick every box of what you would consider FID. I don't think the Qataris, there's any probability of them not building those four trains. They're deep into FEED and into EPC contracts. As a nation, they've decided to do this. That's why you see the dotted line on the chart. We think for all intents and purposes, that is going to happen. 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 looked different.
Of course, if this year plays out in a very linear fashion and everything that looks promising gets FID'd, 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 should we stay on the phone?
One more.
And then we go on the line.
Okay.
Chris.
Thank you. Chris Kuplent from Bank of America. Two questions, please. Just wondered, with that Henry Hub outlook at, let's say, two, 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? 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. 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. I wonder whether you can give us any color on that. Thank you.
Okay. I'll do Canada. I'll let Steve explain how we get through the summer. Yeah, of course, the Canada situation is not totally de-linked from the U.S. situation. When we talked about Canadian returns and prices, we certainly weren't counting on the Canadian gas prices being below $1. 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. The advantages it has in terms of freight and upstream gas cost is, we believe, lasting. Also in today's market, if it was on stream today, we would be happily producing.
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'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 it needs to be evacuated at any cost. That is pushing the gas price down. I'd say at the moment it's very hard to call how long that situation will last.
Yeah.
How do we get through 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. 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. The next two or three months.
Yeah.
Will probably continue to be quite tough.
A lot of energy coming on stream still.
Yeah. We're not necessarily massively exposed to the spot price because of the way we put together our portfolio. For the industry as a whole, yeah, there's probably limited further downside risk from where we are now, but there's not an obvious turnaround that's going to come in the next couple of weeks.
One more here? Yeah. Okay. Oh, Lydia.
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 actually caused that, and what changes this year? Can I just check that the downtime at Prelude isn't related to, that it could force just optional utilization numbers. Secondly, just Maarten, and just in terms of the policy and the challenges to the role of gas in the 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?
Yep. I'll start with the second one. Outside the U.S., for gas to displace coal, it fundamentally relies on policy. Both in Europe, without the carbon price, it's hard to see gas compete with coal. 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, I don't think natural gas has much of a chance. Except for the sectors that cannot be electrified. Too often in the 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, will 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 working hard on them. We believe eventually when policy meets reality, natural gas will have a significant and prominent place in those industries. But it requires continued advocacy from those who see that picture, because 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.
On the other question, this is not a massively significant change. The LNG industry is now of the size that a 1% change in utilization across the whole industry is almost 4 million tons a year. That's all we're talking about, is 4 million tons above expectation. It's hard to predict the utilization across every LNG plant in the world to the nearest percent. No massive change, it's just a function of the timing of maintenance and other things. Prelude is shut down for maintenance. It's not a price optimization.
Okay. We go to the line and then we'll come back to it that way.
We'll hear from Jason Gabelman with Cowen.
Yeah, please go ahead.
One moment, please.
Low cost LNG projects out there-
Oh, sorry. Could you-- Sorry to interrupt. Could you start again?
What?
You were on mute for a bit. Could you start again, because we were falling in the middle of your question.
Yeah, sure.
Go ahead.
Can you hear me now?
Yep. Thank you.
Yeah. There seems to be a lot of LNG projects out there waiting to be sanctioned. It seems like there are more and more that are being presented to the market. 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? A 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 regasification plants. 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 regasification plants at higher levels? Thanks.
Yeah, 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 think quite autonomously about infrastructure. If even half of the announced infrastructure projects in India actually are built, there are 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 in 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 Indian infrastructure, we're not counting on much happening in this outlook. To a large extent, there's an upside to this scenario rather than a downside.
Yeah. 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. As Maarten 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 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 o ver the last five years or so, we have seen a continued reduction in that cost. Yeah.
Okay, thank you. I just wanted to ask about projects or contract sanctity. You talked about record FIDs, record low gas prices. India's out there asking already some other players to renegotiate. Given all that's happened in 2019, are you still confident in contract sanctity across your portfolio?
Yeah. 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. Ultimately, the industry has a tremendous track record of long-term contracts being performed, and we expect that to continue.
Hi. Thanks. Biraj at RBC. One of the things you mentioned, Steve, was the market is becoming more transparent. I guess the futures market and the products are, I guess, getting more complex. I guess having 20% market share in a very opaque market as a trader sounds quite nice. What does that mean for you over time? Is it good or bad having the ability to do more or having more competition? That'd be the first question. 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 or the competing fuel, or is that something that we will see more of over time?
Yeah. 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. 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. 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 de-link our physical position and our pricing exposure much more. If we have a pricing view which would make us want to be short JKM 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 exposed to the pricing whichever direction that we want. There's clearly benefits to our business from the changes in the market structure. In terms of the coal-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. 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 coal indexation without necessarily having the downside of a coal-fired power plant.
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. 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. There were other things in the contract which were attractive to Shell. 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.
This was a really good example of a solution that helped the customer by giving them a solution to their stakeholder challenges, and it helped 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. 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 sold on long-term contracts today. Is your intention to maintain that level of coverage going forward over the next decade? Obviously, we see you taking more volumes into your portfolio with the ultimate intention to kind of lay those volumes off and sign new contracts as you move through the next 10 years.
Yeah. No, 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&L and cash flow statement that you will recognize from looking at our quarterly results for the last 10 years. That's the kind of resilience that we want to bring also deliver to the company's financial framework. We would intend to continue to be predominantly sold on a long-term basis, whatever we buy or own on a long-term basis. 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. That is the ideal way of building out a portfolio. We will always want to keep a bit of volume spot. It is not the preferred risk reward picture of our portfolio.
Thanks. It's Colin Smith from Panmure 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 and CCS related to gas rather than LNG. 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. 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 potential CO2 content in the feedstock. 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.
Thanks. It's a crucial question. 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 cargos to be CO2 offset. I think Steve now already sold three cargos in the last six months to customers that are fully carbon offset using nature generated carbon credits that we buy from reforestation and avoid deforestation projects. You're starting to see 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. I think that business is starting up.
More on the carbon offset side rather than customers saying, "Show to me what the exact carbon content well to the customer's tank is." I'm convinced 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 the CO2 in the reservoir as the CO2 in the upstream operation itself. We set a performance standard for the midstream, and one for shipping. Essentially, if you add all that up, then you get very CO2 advantaged LNG in the tank of the customer that would be at the left end of the curve when customers look at that situation. That's for new energy.
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 energy customers insist on looking through the chain and insist on certain CO2 footprints. We also reflect that in our economics, we charge our economics with an expected CO2 price, not only tomorrow, but also 10, 20, 30 years out, and we burden the economics with that picture. Eventually, I do believe that a gas market will emerge that has certain tranches of CO2 pricing or CO2 products in it. 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 USA, where clearly there's a lot of differentiation in terms of the CO2 content of gas.
It's an active agenda for our new projects. We set significant targets. We also work actively with commercial constructs such as the carbon offsetting to start to create a market that is carbon dependent and carbon friendly.
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 are 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. Thank you very much for your attention, both online and here in the room in London. Okay. Thanks a lot. Bye.