“There is a risk of putting the cart before the horse,” says Christian Zinglersen, director of the EU Agency for Cooperation of Energy Regulators (ACER). In short, it is high time the grid got as much attention as generation. ACER was established by EU law in 2011 to further the integration of Europe’s gas and electricity markets. Zinglersen took over its leadership on 1 January 2020.
In conversation with Energy Monitor, he discusses the latest developments in EU energy and climate policy, defends the controversial new rule stipulating that 70% of interconnectors be set aside for cross-border trade, proposes a strategy to win public acceptance for further build-out of the grid, and suggests how to regulate hydrogen.
What does the EU’s ‘Fit for 55‘ climate and energy package mean for regulators?
New legislative proposals tend to get all the attention. ‘Fit for 55’ is important, but I don’t think we can tick the box on the  Clean Energy Package yet either. We need to make markets work. ‘Fit for 55’ must not come at the expense of making sure the Clean Energy Package is implemented. There are still a number of things outstanding and we are not getting energy markets to function as efficiently as they need to for the EU to reach its 2030 climate goals.
What in the Clean Energy Package has not been implemented, or delayed? What worries you?
First, we need flow-based market coupling [efficient calculation of trading capacities between different market zones, to better integrate them] and a number of elements there are delayed.
Second, we need to make better use of the interconnectors [high-voltage transmission lines across borders] we already have. That is why we have a target in the Clean Energy Package for 70% of each interconnector to be set aside for cross-border trade. We issued our second monitoring report on this target in June and it reached the same conclusion as the first report last year: there is still a lot of work to do.
Third, we face a lot of challenges [to building new electricity lines] today. The energy transition’s accelerating needs are only likely to multiply. We already have significant delays in electricity [transmission] projects, 40% of which involve permitting issues, shows our latest analysis, and so you can imagine the scale-up scenario.
The EU created a Projects of Common Interest (PCI) list with a streamlined permitting procedure to alleviate these problems. Is it not working? What else could help?
The one-stop-shop principle for PCI projects is sound, but when you look at scaling up the needs for [grid] infrastructure going forward, you will probably also have to look more closely at a territorial type principle.
So far, the costs for infrastructure projects typically accrue to the territory they are in. There is a regulatory possibility to be more flexible, to attribute the costs to where the benefits are. If country A gets 40% of the benefits, it would get 40% of the costs, even if half of the construction is in its territory. This principle is not yet applied very often; when it is, it is often because there is external funding.
In future, if you are looking at scaling up very significant transmission infrastructure over thousands of kilometres to bring offshore wind from the North, Baltic or Black seas to continental Europe, you will need much more transit infrastructure and this will probably require a significantly different distribution of costs and benefits.
How do you build public acceptance for large, long-distance transmission lines?
Delays can in part be attributed to a lack of public acceptance. There is a perception of no, or not enough, local benefits. If projects become more transit-oriented, it is a safe bet this issue will escalate. We need a political conversation about how you can provide for localised benefits. This is not getting the attention it deserves.
There is no predetermined model for how to do it or who pays. It could be funding for local nature protection projects from a premium on local grid tariffs. Or it could require a broader compromise similar to that for the big coal phase-outs. The strategies some countries are pursuing for these are almost nationwide and involve the taxpayer base. The imperative is climate and energy, but the toolkit is social, regional and economic policy.
Can the grid be built up fast enough to keep pace with the energy transition?
Faster permitting, cost redistribution and wider societal compromise will need to be part of that package. We also need more integrated planning, to get energy from generation to demand. When policymakers speak about offshore wind, they talk about a meshed grid, and a mix of electrons and molecules, but what happens when the energy comes onshore? How is it transported to load centres? That part does not get enough attention.
How much more can we do with our existing grid assets?
It is important to maximise the capacity that is available. Hence the 70% target for international trade on interconnectors, so that consumers benefit from the cheapest sources of electricity available in the market while not endangering security of supply. However, there are also technologies that system operators can use to enhance the efficiency of individual lines, such as dynamic line rating [or maximising load according to local temperatures]. We probably need to look more closely at how to incentivise these.
To what extent this is already done depends on each country’s regulatory tradition. Typically these technologies cost a bit but not very much more, and so if you only regulate for Capex, operators are not very incentivised to apply them. If, however, you look at optimising operational efficiency or try to develop broader benefits notions, you can provide a stronger incentive.
That said, there are significant scale-up challenges ahead and we cannot optimise our way out of them fully. We will need to build more grids.
In an interview with Energy Monitor in June 2021, Tennet CEO Manon van Beek argued that the 70% rule on grid capacity may hinder rather than promote offshore grids. Yet, you have stressed its importance. Should we worry?
There is a risk of putting the cart before the horse. Vast offshore generation should not be an aim in itself. It is a means to an end: vast renewable electricity generation at scale that can, over time, get to load centres at attractive prices.
Let's say that for a significant amount of time the wind at an offshore farm is outcompeted by lower prices elsewhere and that other power takes up a significant portion of the cables the farm wants to use. That is obviously not good for the generator, but it is not necessarily a bad thing for broader European society if you are getting cheaper prices than this particular farm could provide.
The logic of where and how much you invest in generation – future demand patterns, congestion and curtailment risks – does not disappear just because it is a vast offshore site. You still need to sell your power. You cannot say 'I want to build 10GW of generation over here and then I’ll figure out how to sell it'. Let’s figure that out first and then build it.
Is there a risk of cheap but dirty power pushing out clean renewables on interconnectors?
The European power supply is being decarbonised by the EU Emission Trading Scheme (ETS). Five or six years ago at a carbon price of €5 a tonne (€/t), one could legitimately have asked this. That is less easy today. This week, the carbon price rose to an all-time record of more than €60/t. Today, different electricity mixes are engaging with each other in an increasingly decarbonised grid.
Moreover, in the North Sea, wind power electrons may often be competing with Norwegian hydropower electrons that are also zero-carbon. The long-term solution here could be to build more interconnection capacity.
I take the point that there is an issue around revenue certainty for the generator, however. The 70% target brings up the need to look at the distribution of revenue between those who own the interconnectors – and make money from congestion – and the generators. This is a genuine issue. If a generator faces less revenue because interconnectors are sometimes 'taken up' by trade, those who make a lot of money from that trade should probably share the pie. The European Commission alluded to this in its offshore renewable energy strategy last year.
What role do you see for hydrogen, especially green hydrogen, as a way of transporting and storing energy in future?
At first glance, I would say transporting energy in pipes, new or repurposed, offers very attractive costs per volume. However, you have to balance that with the conversion cost of producing ‘pipeable' energy. Green hydrogen does not currently have a very attractive price profile vis-à-vis renewable power. Some people suggest the business case for electrons and molecules is roughly similar. I do not think that is the case.
One of the key principles we need to keep in mind when we look at hydrogen, of whatever colour, is the importance of having locational signals that testify to the value, or lack of, of a specific location. You can do that by connection tariffs – connecting somewhere is more expensive because it is far away from production or consumption – or by trying to capture the value of avoided grid enforcement investments.
This locational element has increased in importance as renewables have gone mainstream and I suspect it will be the same for hydrogen.
What policies will get the hydrogen economy up and running in Europe?
Policymakers should take lessons from the European gas market. Gas networks were in place. The market was highly integrated and underwent a process of liberalisation. Hydrogen will be the opposite: industrial clusters already use it, but hydrogen infrastructure and the associated market still need to be developed, and the idea is to scale up its use to other sectors. It will benefit from the gradual building up of a regulatory framework based on gas market principles, such as third party access provisions, and monitoring and regulatory oversight.
I do not think regulators need to impose a colour preference [for green or blue hydrogen], with the EU ETS coming of age and possibly combined with a Guarantees of Origin system.
Is natural gas still important for security of supply?
Here and now it is. The question is whether it will be as critical in future. This is difficult to say. The same is true for baseload. I think there will be a need for dispatchable generation as a form of flexibility, but whether this needs to be natural gas or whether it could be renewable gas – if costs come down – is an open question. I am not sure it needs to be natural gas in 10–15 years from now.
What is the role of the demand side and a more decentralised infrastructure in balancing the future energy system?
There is no doubt that a lot of balancing between supply and demand will take place at the local level using local assets – but it is also difficult to imagine a fully decentralised system. No one knows what the mix of storage, electric vehicles, demand response and interconnections will be. I think there is likely to be intense lobbying for individual solutions and we need a market framework that allows all these options to play out against one another.
As regulators, we definitely have work to do. One of the aims of the Clean Energy Package was to level the playing field for the demand side. ACER has started monitoring this and may come forward with suggestions to tweak network codes to better enable it. This is one of our priorities for the coming years.
Our overarching priority is to promote integrated markets for decarbonisation. One key area is the European resource adequacy assessment proposed in the Clean Energy Package for which we will start to map out a methodology later this year with ENTSO-E [European electricity network operators]. This is resource optimisation from a European, rather than national, perspective. There are a lot of technical details to sort out, but the big question is whether the political comfort levels are there for such interdependency. This is, in my mind, a prerequisite for decarbonisation.