Energy TSOs: ‘We see 300-800 TWh of renewables feeding into electrolysers by 2050’

German Economy Minister Philipp Roesler (C), inaugurates a hydrogen power-to gas pilot plant in Falkenhagen, Germany, 28 August 2013. Wind-generated power is transformed into hydrogen and injected into the gas transmission system. [EPA/NESTOR BACHMANN]

With Europe’s climate neutrality target soon becoming law, energy TSOs have launched joint scenarios to test gas and electricity networks against growing shares of renewables. Under current plans, they foresee 300-800 TWh of renewables feeding into electrolysers by 2050.

Anne Boorsma is director for system development at the European Network of Transmission System Operators for Gas (ENTSOG). Dimitrios Chaniotis is system development committee chair at the European Network of Transmission System Operators for Electricity (ENTSO-E).

They spoke to EURACTIV’s Frédéric Simon about the challenges of decarbonising Europe’s energy system, and what this entails in terms of infrastructure.

INTERVIEW HIGHLIGHTS:

  • Gas and electricity TSOs are currently preparing joint scenarios to inform policymakers about the challenges of decarbonising the energy system up to 2050.
  • So-called ‘sector coupling’ between gas and electricity is seen as more relevant for the 2030s than in the short term, but preparation work already has to start now.
  • For the electrification of transport, €100 billion in new infrastructure is foreseen until 2030, a figure that may have to be revised upwards with the EU’s new climate targets for 2030.
  • Models point to a growing interdependency between gas and electricity carriers. The more renewable electricity comes online, the more intermittent it becomes, the greater the need to rely on hydrogen.
  • Under scenarios consistent with the Paris Agreement, gas demand falls from around 5,000 TWh today to around 4,000 TWh in 2050. And unabated natural gas is expected to reach zero by that time.
  • The gas remaining in the system by 2050 is either renewable or decarbonised – before or after it reaches Europe. But TSOs cannot predict with which technology, whether hydrogen in different forms, or CCS.
  • In all cases, decarbonisation will require a massive build out rate of renewable gas generation in Europe, biomethane and power-to-gas facilities. For power-to-gas, that means 300 to 800 TWh of renewables feeding into electrolysers by 2050.

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With the exception of Poland, the European Union has now unanimously agreed an objective of reaching “climate neutrality” by 2050. What does this mean in terms of infrastructure development for both electricity and gas?

Anne Boorsma (ENTSOG): We developed three different scenarios in our respective Ten Year Network Development Plans (TYNDP). The first is the central policy scenario, based on currently agreed policies, in line with the National Energy and Climate Plans (NECPs).

That’s assuming a reduction of 40% in greenhouse gases for 2030, right?

AB: Yes. And then next to that, we also did two so-called COP21 scenarios, which reflect a more climate ambitious approach, with a carbon budget in line with the 1.5°C objective of the Paris Agreement.

We made these scenarios for a specific purpose, and that is to test the electricity and gas infrastructure against these developments.

Now with the European Green Deal going forward, we could say these scenarios also cover the 2050 carbon neutrality objective.

Dimitrios Chaniotis (ENTSO-E): In essence, we’re preparing the scenarios until 2050. We’re looking at the infrastructure on a 10-year horizon because this is the mandate of the TYNDP. But the 2050 analysis we’re doing is to give a direction to our TSOs about the challenges that are coming.

And indeed, depending on which scenario you’re looking at for 2050, you do see the urgency, of taking action already today.

For example, when we talk about sector coupling, which is the buzzword in Brussels right now, this is not something we anticipate to see materialising in the next 10 years. This is something we see more relevant for the 2030s. But we have to start working on it now if we want it to happen later on.

Another example is digitalisation. This will revolutionise the operation of our grids in the future but it is something we should start right now, which is what we’re doing, because it’s not easy to change the infrastructure like that.

So in essence, we see the challenges, we see the functioning of the gas and electricity sectors together in an optimal way. And it’s not just gas and electricity, it’s heat and transport networks as well. We see the challenge of digitalisation and how this will impact the way we operate the networks. We see a lot. But again, these are just scenarios – more tangible conclusions will come with the TYNDP analysis done by ENTSO-E and ENTSOG separately.

Apart from sector integration and digitalisation, what else is driving change in energy networks?

DC: The interaction between the distribution and transmission level is a major one. A lot of the new power generation is being connected at the distribution level. That will redefine how we operate, including access to flexibility services, which is crucial for the stability of the system. This is what sector coupling is all about – flexibility, how to get access to this flexibility and how to make the system operate securely.

What we’re doing now already allows us to prepare for those challenges coming after 2030.

For decades, your mission at TSOs was to deliver gas and electricity wherever it’s needed. Is this mission statement now changing with the carbon neutrality objective? Isn’t the mission statement now increasingly to aim for zero emissions as well?

AB: It’s difficult to comment on that. I always say that the infrastructure itself is not generating carbon emissions. It is the content of the grids – whether electricity or gas – that is doing so. In a way, we are only the highways and whether it’s used by diesel cars or by electric vehicles, that doesn’t change the highway.

But you have to make sure the “highways” are capable of handling new cleaner types of vehicles – in the case of TSOs, renewable gas or electricity.

AB: Yes. And that is why we try to build scenarios that are relevant for this challenge.

DC: But don’t reduce our mission to just transporting electricity. Our mission has always been to operate the system securely. And it’s also about operating and developing this system in the most cost-efficient manner.

These missions remain, and they become even more relevant with increasing shares of renewables. We are enablers of policies, we’re not designers of policies. Our mission is to inform policymakers of the consequences of decisions they take. And we do this every year at ENTSO-E with our resource adequacy forecast, which complements similar analyses made by national TSOs.

BA: On the gas side, we are already used to work on market functioning and security of supply aspects. The sustainability and decarbonisation aspect was not yet in any European regulation as a task for the gas infrastructure operators. We anticipate that this is also our task to be prepared for it.

We are in the middle between producers and consumers. So, I think in any renovation of the approach to the energy system, the TSOs have a central role to bring this all together.

You mentioned data and digitalisation as one of the big challenges you’re faced with. We saw how difficult it was for electricity TSOs to exchange information when calculating available capacity across borders. So adding gas operators to the mix will make it even more challenging in the future. Would you say smooth and transparent exchange of data between electricity and gas transmission system operators is a desirable objective to aim for?

DC: Data flows between electricity TSOs, at least for the adequacy analysis, is working quite smoothly. It’s not that we are discovering the European aspect of adequacy now, it is a decades-old task of the TSO community and ENTSO-E. We just have to improve our methodologies in order to make it even more transparent and up to the task of the Clean Energy Package. And it is part of the mission of ENTSO-E and the TSO community to work on harmonising methodologies.

I understand this is not yet the case…

DC: No, it’s not yet the case. And that is for a good reason: sometimes you reach a limit where you have to ask whether it makes sense to push harmonisation further. Because ENTSO-E is a network of networks – each with very different characteristics. And sometimes the methodologies are not applicable from one country to the next.

For example, an energy system that is dominated by hydro, you don’t analyse it with the same methodology than an energy system dominated by wind or nuclear. So, you have to determine how far it makes sense to go with harmonisation.

But the main objective is to work on a common understanding in terms of data. This is something we’ve been working on for 10 years with our adequacy forecasts. And those should always be complemented by national visions.

Building bridges between electricity and gas in the way you calculate adequacy: has that work started, or is it still too early?

AB: From a system development perspective, gas and electricity TSOs follow separate trajectories.

However, we are also in the process of defining an interlinked model to determine whether some projects require a dual assessment at European level. A study was made for both ENTSO-E and ENTSOG to define rules for selecting projects with dual assessments.

It won’t be a comprehensive joint model to make a complete assessment of everything because that would be way too much. But at least we will start with some specific projects and make a dual evaluation assessment of those. Maybe it will not be available in this year’s coming TYNDP but in the series after that, we hope it will.

Now, this is the European level. But in the end, network development happens in the Member States. In the Netherlands for example, TenneT and Gasunie have done an infrastructure outlook and they are now doing a proper common system development plan. With an increasing share of renewables in the energy mix, it becomes more relevant to do joint system planning in this way.

You’re saying the Netherlands is a trailblazer when it comes to integrating electricity and gas networks and doing some joint system planning?

BA: It’s also is happening in Germany, it’s starting to happen in Italy…

DC: In Denmark and France also. Many countries have started exploring the expected contributions of sector integration to a cost-efficient energy transition.

But it’s still early days, I guess.

DC: Oh yes. But I think it’s important to make a clarification. The TYNDPs are very long and complex exercises, with several phases. There is a phase of scenario building, a phase of identifying investment needs, and a phase of evaluating projects.

The scenario building is a common phase ENTSO-E and ENTSOG are doing jointly. But the other two phases are still separate. So in a sense, it is not accurate to say the TYNDPs are exactly the same. No, it’s the scenario phase that is done jointly, because this is where we get the most benefit from our collaboration.

In the future, we may also consider doing joint evaluations and projects, leading to a joint evaluation of investment needs. But so far, it’s only the scenario building, which is common to ENTSO-E and ENTSOG.

BA: Yes, with the joint scenario development, we already have an interlinked approach. And now we can look for further improvement.

Let’s focus on electricity for a moment. In its long-term strategy, the European Commission predicted that 53% of energy demand in Europe will be met by low-carbon electricity by 2050 – mainly renewables and nuclear. That means massive investments in electricity infrastructure. How is that reflected in your network development plan?

DC: Our scenarios confirm the tendency of going to this level of electrification. But we have to question what the 53% refers to. Because overall energy demand will go down in the coming years as a result of energy efficiency measures. It may even go down dramatically, depending on the estimates.

So the 53% figure will apply to a lower volume of energy than we have today. This is not to minimise the task, which is enormous. For example, in terms of transport, I cannot give you figures of what infrastructure will be needed because it doesn’t go to 2050. But the pathway to get there, the milestone for 2030 – this is something we will evaluate in the next TYNDP.

So you will have a figure in terms of how much infrastructure investments will be needed for the electrification of transport, but you don’t have it now?

DC: Exactly. For the 2030 horizon, we have the new scenarios now. Then we have to evaluate the projects in order to reach the 2030 milestone. This is based on the current objectives because the pathway may change.

And what is the figure?

DC: In the previous TYNDP, the scenario was in the order of €100 billion in terms of transport infrastructure for 2030.

That is with the current objective – a 40% reduction in greenhouse gas emissions by 2030. Now, with the European Green Deal, we’re looking at a 50-55% emissions reduction by 2030.

DC: This may evolve, yes. But again, it depends also on how you address this transition. Because although transmission lines are the immediate, most efficient solution to cover the needs for electric demand, there could be also other solutions. It’s not about pushing new transmission lines at all cost – there could be other solutions as well.

New transmission lines cause resistance in some places. This is particularly visible in Bavaria, southern Germany…

DC: Exactly. And our task, through the TYNDP and the national plans of the TSOs, is to convince society that whatever solution we put on the table is the most cost efficient one, the most beneficial for society to reach the targets. That’s our challenge.

The number one priority for us is permitting for new power transmission lines. To ensure public acceptance, politicians and authorities have to take ownership of the energy transition and promote these projects with TSOs.

We should recognise that delaying a project because of permitting has a cost. And this cost should be reflected in the investment decision.

Can the EU help speed up permitting for new power lines?

DC: It’s mostly a local issue. On the other hand, EU guidelines for trans-European energy infrastructure have had a positive effect, with the EU label of Projects of Common Interest (PCI). The One Stop Shop also had quite a positive effect in certain areas of Europe. So there are ways in which European action can help.

Public resistance usually focuses on big overhead power lines. Burying them is better from a public acceptance point of view but it’s more expensive as well. Is that what you’re recommending?

DC: Burying is one of the solutions. But again, it won’t apply to the whole of Europe because the sensitivities are different from one country to the other.

What are the other solutions?

You can reuse pathways. For example, the French-Italian interconnector uses existing train tunnels to minimise the impact. There are many solutions from the cheapest to the most expensive, one of which is to bury lines underground. We’re also looking at new technologies – innovations in transmission. But regulations do not always encourage this.

AB: In the Netherlands, TenneT and Gasunie looked at the challenge of integrating a lot of renewables coming from the North Sea. And they came up with a hybrid solution combining the electricity grid and the gas grid.

Netherlands has a lot of gas pipelines which are situated close to energy generation units. And using the gas grid allows decreasing the need to build new electricity lines by using the existing gas grid. Now, that is not necessarily a solution that is valid all over Europe, but in some parts it could also be part of the approach.

DC: In terms of integrating renewables and ensuring grid stability, all solutions are on the table.  But they have to be proven, they have to be tested. That’s why what they’re doing in the Netherlands is quite commendable: you have to test to see whether it’s realistic to go this way or not.

Let’s turn to gas, now. Looking at the Commission’s 2050 scenarios, the stated 53% share of energy demand that is expected to be met with low-carbon electricity means a smaller space will be left for gas – at least fossil gas. How is that reflected in the TYNDP?

AB: When talking about a 53% share for electricity, you first have to determine total demand. According to Commission scenarios for 2050, electricity demand ranges between 3,500 and 3,900 terawatt hours per year. That is in the Commission’s long term 1.5 °C scenarios and it is more or less in line with our joint ENTSO-E and ENTSOG scenarios.

What are the implications for gas infrastructure, then? Net-zero emissions by 2050, how does that translate for you in 2030 in terms of infrastructure planning?

AB: Our joint scenario applies a carbon budget approach, trying to examine energy demand for the different carriers. For households, we try to assess how much gas boilers, electric heat pumps, or hybrid heating systems combining electric heat pumps and gas boilers will be online. We do the same for transport and industry, assessing demand for all sectors.

Then we look at the generation side: where is this electricity coming from, where is the gas coming from. And that’s how we arrive at the scenarios for gas and electricity.

So with a growing share of electricity by 2050, what does that mean for gas infrastructure?

AB: There will be an important exchange between the two carriers. An obvious one is the gas that is used for power generation. In the distributed energy scenario, which has up to more than 80% renewables, demand for gas-to-power generation is higher than in the global ambition scenario.

And the other way around – power-to-gas – is also important. The more renewable generation you have, the more intermittent it becomes, and the more you need to rely on hydrogen.

So, it means that there is an important interdependency between the two carriers. What we are promoting in a way is something like a joint system, a hybrid system or a system of systems.

We may have different words at ENTSO-E and ENTSOG to characterise this, but the concept is the same. Part of the energy transition will be done with electricity, and the other part will be done by gas.

But we can’t give a market share simply because we don’t know. What our scenarios reflect is possible futures for how the gas and electricity carriers could serve demand for energy in the future.

Let me formulate this differently: Most experts say natural gas will remain crucial until 2030 to displace coal and bring energy emissions down. But beyond that date, the amount of fossil gas in the system will need to decrease steeply in order to keep in line with the Paris Agreement. How does the new TYNDP reflect this?

AB: We recognise all this. In our scenarios, indeed, the share of unabated natural gas goes down and is expected to reach zero by 2050. Then, the different gases that are still in were defined in the Gas for Climate study done by Navigant and the Trinomics study for the Commission.

These include biomethane and hydrogen from power-to-gas. As far as it is generated from renewables electricity, it also includes renewable hydrogen. And then of course, an important part can be played by what used to be called blue hydrogen – or natural gas that is treated through steam methane reforming or pyrolysis to take out the CO2.

And there is the option of doing post-combustion carbon capture and storage (CCS). For example, a large factory that still receives unabated gas could try to capture the CO2 and store it underground.

All of that is reflected in the scenarios. But we do not exactly know which technology will prevail. I think we will need all contributions – a single one will not do it. And it has to remain technology-neutral. So whether the hydrogen will be decarbonised first, for example, in Australia and then brought here or brought to Europe and then decarbonised here, we don’t know.

Not all green gases will be imported. Some will also originate from Europe itself but we don’t know yet in which proportions. What we do know is that to meet the future climate targets, the gas will have to be more and more decarbonised.

There are increasing amounts of LNG imported from the US, notably. New terminals have been built over the years, which are not always used to their maximum capacity. In your current scenarios, do you foresee a lot more of those terminals being built? And are they future-proof? For instance, could they take hydrogen imported from faraway places like Australia?

AB: We first do the supply and demand analysis. And if there is a gap, we do project collection from promoters and then we assess the projects that we receive. So we are able to say which project adds value, and which one do not solve anything. But we don’t propose what should be done.

Now of course, currently the pipelines from Norway, Russia and also the LNG terminals always bring unabated natural gas to Europe. But that does not prohibit decarbonisation steps to be taken thereafter.

So either it is already brought to Europe decarbonised, for example liquid hydrogen, which is already possible from a technology point of view. Or it can be decarbonised in Europe, with the appropriate facilities.

And that implies building new infrastructure for decarbonising the gas, right?

AB: Yes. If you have the decarbonisation step after the gas arrives in Europe, it would indeed require an additional piece of infrastructure to decarbonise the gas. But the existing terminal could still be used.

Overall demand for energy is expected to be lower in 2050. And demand for fossil gas has to fall to zero in order to keep with the Paris goals. Does that lead you to identify already now some potential stranded assets – such as gas pipelines that will no longer be in use?

AB: Our scenarios foresee a slight decline in the demand for gases which is currently around 5,000 terawatt hours per year depending on whether the winter is cold or not.

Now, with the accelerating coal phase-out, we see demand for gas to rising slightly until the 2030s and then declining over time from around 5,000 TWh today to around 4,000 TWh in 2050.

And that assumes all fossil or unabated gas is eliminated from the system?

AB: Yes. Gas consumption goes down to 4,000 TWh by 2050 in our scenarios. The current composition of gas consumed in Europe is mostly unabated natural gas. There is only limited amount of biomethane. And most of it is imported from outside the EU, including Norway.

But over time, we see the composition evolving. By 2050, we still foresee some unabated imports arriving at the EU border, but in the end everything is either renewable or decarbonised.

In our global ambition scenario, you see that the share of imports (currently 70%) increases in the coming years and then goes back down to 70% by 2050.  In the distributed energy scenario, the share of imports goes down to 35% by 2050. And that will require a more massive build out rate of renewable gas generation in Europe, biomethane and power-to-gas.

And so, are there any obvious implications in terms of infrastructure?

AB: Yes. First of all, looking at the composition of the gases, we have to make sure that infrastructure is ready to transport it. And from the ENTSOG side, we just published our Roadmap 2050 for Gas Grids where we state our vision of a hybrid energy system combining gas and electricity.

We identified three different pathways to transport those gases – a methane pathway, a pure hydrogen pathway, and a blended approach. These pathways could co-exist in different parts of Europe and even within one country. In some countries it will be mostly methane, based on more biomethane in the grid, like in Denmark or France. In some, it will be pure hydrogen like the Netherlands, which is considering a hydrogen backbone, connecting also to industrial regions in Belgium, Germany, and Northern France.

Then there could be a blend, with methane-based gases, and also some power-to-gas which generates hydrogen. Now, that may not be enough to have a pure hydrogen backbone, but if it could be injected as a blend, up to some percentage.

So that’s how we see the infrastructure by 2050: it could be a combination of these three pathways.

But does that mean different if infrastructure for all three scenarios possibilities? Or can the same pipeline carry all these different types of gas?

AB: Again, using the Netherlands as an example, we have already a long experience with transporting different qualities of gas. The gas from the Groningen field is low-calorific gas and in parallel, high-calorific gas is transported from Norway or from LNG. These are really different qualities which are managed by the same TSO. The production can enter the system, using separate pipelines, but it is part of the same gas system.

They are different branches of the same pipeline then?

AB: Yes. And the same concept could be used for example if you consider a methane blend next to pure hydrogen.

If you have so many different qualities of gas – fossil, decarbonised or renewable – it means you have to have different infrastructure to carry these different gases. That means investments in new infrastructure probably, then?

AB: There is already a lot of gas infrastructure available. This is the starting point. And this means checking whether existing infrastructure is able to take a certain share of hydrogen, up to 100% hydrogen. We are currently working with our TSO members to find out what is the current status.

And then the next question is how the different TSOs want to prepare their system: which pathway they choose, whether it is methane, pure hydrogen or a blend.

These questions are not all answered, but again the starting point is that we could use the existing infrastructure and adapt it to the different pathways that are necessary to deal with these different gas qualities.

So, there won’t be any stranded assets?

AB: Well, that remains to be seen… But we should inform about possible optimisation and synergies from using the existing infrastructure.

Presumably this is unavoidable, no? If there are a lot less imports coming from, say Russia, it’s unlikely that this infrastructure is going to be used indefinitely. Or is that not clear yet?

AB: It’s not clear yet. Actually, we are still before the TYNDP exercise. At the moment, we are focusing on the challenge of decarbonisation and the hybrid system approach combining gas and electricity.

The perception used to be that electrification would be the way forward. I think more and more now, that perception is changing. Both the electricity and gas carrier are part of the solution.

Now, we are only at the beginning of decarbonisation. If the infrastructure is no longer necessary then of course, it will be taken offline. But we’re not there yet.

DC: The stranded assets question is also relevant for the electricity sector. By the way, these scenarios, both for gas and electricity, are not predictions of the future. They are constructed to test the infrastructure that we put in place today in order to see how it performs economically in different futures.

For electricity, one of the scenarios is increased flows of wind power coming from the north to the south east. The other scenario is more solar power coming from south to north. These are two different configurations.

So whatever investments are being made today, we have to make sure that the infrastructure withstands the test. That’s how the scenarios were constructed.

I understand that for gas, the stranded asset question is even more complicated because there will be different qualities of gas, with methane, hydrogen and blends. Whereas for electricity, the grids transport electrons today, and will continue to transport electrons tomorrow.

Irrespective of how much gas is going to remain in the system – whether fossil or renewable – what matters is actually the role of the networks. And with sector coupling, the question is how the gas network is going to enable the decarbonisation of electricity. And at the same time, how the electricity network is going to enable the decarbonisation of gas.

This is the essence of sector coupling. And our joint TYNDP scenario is our platform to answer this question.

So what did you find? How can the gas sector help electricity to decarbonise?

DC: Gas-fired plants already provide flexibility to the electricity system now. So, you have to decarbonise the fuel that goes into these power plants. Then power-to-gas can also provide flexibility to the system, using excess production of renewables that cannot be absorbed by the system.

This is what we call sector coupling. But we’re just at the starting point. Because the scenarios evolve – every two years, we come up with new scenarios. And there can be complicated questions. There’s a lot of uncertainty in terms of technology, both for gas and electricity. The essence is to determine how the two systems can work together to decarbonise. But how much electricity and how much gas? We’ll see.

Gas-to-power and power-to-gas also require investments in new infrastructure. How many electrolysers do you have in your scenarios? It’s near zero at the moment, I understand…

DC: We’re in the order of 300 to 800 TWh of renewables feeding into electrolysers by 2050. In a sense, this is a huge number. It’s partly motivated by the volumes we foresee to decarbonise gas.

Now, we don’t know yet where they’re going to be located or how they’re going to be operated – on renewables, nuclear, or whatever else.

This is quite a complex issue, and we’re just starting to model it and understand it. What you see in this scenario is not the outcome, it’s not how much power-to-gas is needed. This is how we think the interaction between the two systems is quantified. But we cannot assess it precisely at this point in time.

But it will come eventually?

DC: Yes, we will assess it.

AB: On power-to-gas, we collect projects for the TYNDP. And we used to have project collection for gas pipelines, gas storage and LNG terminals. But now for the first time, we included a new category called energy transition-related projects.

And here, we asked the promoters to submit projects that can contribute to decarbonisation. We received more than 40 projects in this category which is already 25% of the total projects received. And if you look in what categories they are, the majority is in power-to-gas and making pipelines suitable to carry hydrogen.

Some projects are about connecting to biomethane facilities, some are about CCS, others about reverse flow, to support the flow of biomethane from the DSO to the TSO level.

Not all are yet very advanced. But it is starting, and the majority is in the area of sector coupling, preparing for the combination of the gas and electricity systems.

Staying with power-to-gas and electrolysers: did you do a cost-benefit analysis? For instance, how do you know when it makes sense to use offshore wind to produce hydrogen, considering the conversion losses? There are fewer losses injecting the power straight into the electricity grid, so how do you when it no longer becomes worthwhile?

DC: Let’s get this straight. Energy conversion is in general terms to be avoided, as you lose in efficiency. So if you see it like that very narrowly, power-to-gas doesn’t make sense. But if you look at the density of energy, gas is more interesting than electricity.

What we need to have is a more holistic picture. Power-to-gas could make sense economically. But how much I cannot tell you, and it will vary from one country to another.

We should be sincere here. The work has just started. And we need to have the whole picture before making an opinion. My feeling is that in certain areas of Europe, power-to-gas could make a lot of sense, because of the particular characteristics, the installed infrastructure, and so on.

Typically in places like Sweden where they have a surplus of renewable electricity, right?

DC: Yes, exactly. And in other countries, it won’t make sense. Our task is to analyse this. And in terms of cost-benefit analysis, this is something on which ENTSO-E and ENTSOG are working together. It’s a very interesting domain.

And I hope we can come up with some hints about how this can be done in the next TYNDP. But it’s not an easy task. Depending on how you define the scope, you can come up with different results to your cost-benefit analysis and this therefore needs to be exhaustively tested.

AB: As TSOs, we are not in a position to design the optimal energy system. Instead, what we do is to collect information from all over Europe, and prepare scenarios to test the system.

And then we find out whether there are gaps. Many initiatives are blossoming. And we’ll find out over the years what works well and what doesn’t. I believe more in this approach than in a central planning approach done by some institutions.

European industry is currently at the forefront of electrolyser manufacturing. Should the Commission take an initiative for electrolysers similar to what’s been done with the European Battery Alliance – taking a whole supply chain approach?

AB: I find it hard to answer. If you look at batteries, there was a technology innovation question and also an issue regarding the availability of materials from outside Europe. So there, I can understand the interest.

Now, if you look at electrolysers they are already applied in the chemical industry and process industries. The technologies have already been there for decades. So far, there was probably no business case to apply it in sector integration because there are cheaper alternatives. But now if the cheaper alternatives are no longer viable because of decarbonisation requirements, then you start to have a need for scaling up.

DC: We should be agnostic on this issue. But I would tend to disagree on the business case. Electrolysers are also infrastructure which can be used for coupling electricity and gas systems. It’s a technology that is seen by TSOs as an important instrument to enable the transition. And it is important to scale up, to start testing, and get information on how they can benefit both systems.

There is currently no operational experience on electrolysers at large scale. We need to get experience, we need to get this information in order to better design the system of tomorrow – if electrolysers are to become a big part of it.

Our scenarios suggest electrolysers should be part of the picture tomorrow because this is the most prominent way to decarbonise gas. So for me, they should be part of the picture. But again, this is the future we’re talking about. It’s important also to understand what Greta Thunberg said: It’s easy to set targets for 2050 but that doesn’t mean you will reach them. By 2030, there are still investments to be made. People should not lose focus on what needs to happen today.

AB: ENTSOG and ENTSO-E published a joint paper on power-to-gas last year. And one of the statements was that this will require scaling up. And that we should start now.

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