Regional electricity bidding zones in Germany – grid relief or price trap? Double interview with Prof. Dr Hans Schäfers (HAW) and NRL project coordinator Mike Blicker

The debate on the division of the Germany-wide electricity bidding zone into several regional zones is not new, but it has picked up speed again with the calls of the heads of government of the northern German states of Bremen, Hamburg, Mecklenburg-Western Pomerania, Lower Saxony and Schleswig-Holstein in the summer of this year. Views on the consequences of this sort of division on electricity prices and, as a consequence, hydrogen prices, grid expansion and Germany as an industrial location are contentious. In an expert interview, Prof. Dr Hans Schäfers (head of CC4E at HAW Hamburg) and Mike Blicker (project coordinator of the Northern German Living Lab (NRL) joint project) provide a realistic insight into various scenarios.

EEHH: Can you briefly explain the concept of the uniform electricity bidding zone and why it has been considered a central pillar of the German electricity market up to now?

Prof. Dr Schäfers: In the conventional fossil-fuel system, the electricity was generated in the power plants in such a way that it was fed into the grid at the highest voltage levels and then passed down to the consumers via the various grid levels (high voltage, medium voltage, low voltage). In a funnel system like this, generation can be bundled at the highest voltage level and marketed in a uniform system. Moreover, the power plants are distributed geographically across the Federal Republic, meaning that a large market with high generation capacity in a bidding zone has evolved and grown with this model. The merit-order principle made it possible to create incentives in this system for the most efficient and cost-effective electricity generation possible.

EEHH: How is this regulated in the EU? Do the individual member states also have their own national electricity bidding zones?

Prof. Dr Schäfers: Historically, national electricity bidding zones have emerged in neighbouring European countries too. Although there is a certain amount of exchange in the interconnected grid with neighbouring countries, this is limited by the capacity of the interconnectors / border interconnectors. This means that there cannot be an unlimited exchange of electricity between EU states. A stronger cross-border exchange would further reduce the price of electricity and is therefore politically desired.

EEHH: Why is a split being discussed now? What structural problems in the German electricity system is this supposed to solve?

Prof. Dr Hans Schäfers: Since we are increasingly replacing fossil fuel power plants with renewable energies, the physical conditions have changed. The electricity from wind and solar is usually not fed into the grid at the extra-high voltage level (380 kV), which is necessary for long-distance transport, rather primarily at the medium-voltage level. This means that grid capacities that were never built for this distribution now have to transport these amounts of electricity. As a result, our current system has limited exchange capacities at grid interconnectors, and not between EU countries, but between different regions in Germany. There is a striking division between north and south in particular.

Physically, the south cannot consume more wind power in the north than can actually be transported via the grids. However, trading is not limited at all. And there is no consideration given to this at all at the moment. In day-to-day business, it is often the case that more electricity is purchased than can be physically transported. At the same time, the grid operator is not allowed to intervene in the market, despite being aware of the situation, and can only react to the grid bottleneck the following day. As a result, redispatch is then ordered, which is extraordinarily expensive. A division of the common electricity market would significantly reduce the need for redispatch. The market could then take the actual transport possibilities into account, similar to trade with our European partners.

EEHH: What opportunities and risks would a division of the electricity bidding zone have for Germany as a whole – both for consumers and for industry and the energy transition?

Prof. Dr Hans Schäfers: The biggest risk for industry is the loss of planning security. Electricity price forecasts based on existing tools and empirical values would be obsolete for the time being. Another risk is an expected price increase in the load centres due to reduced supply volumes. At the same time, higher electricity prices could create incentives in industrial centres (in the south) for expanding additional production capacities there. Grid expansion, too, would be incentivised by the price differential, as there would be a financial interest in physically transporting cheaply produced wind power to the south. The decisive factor is the price: is it cheaper to lay thicker lines to the south or to build more production capacity in the form of wind and photovoltaics in Bavaria and Baden-Württemberg? There is also some concern that industrial companies could move from the south to the north.

Another counterargument is that the process of division into new electricity price zones will take five to six years. At the time of the predicted completion of the process, the grids are expected to be sufficiently developed in line with the forecast today, meaning that the split could prove to be more or less redundant again by the time it is up and running. Our simulations confirm this for the early 2030s, but this would no longer be the case again from 2035, as production capacities for wind power in the north continue to rise sharply. If we wanted to convert the electricity system completely to renewables, we would have to triple the current 200 GW of RE electricity generation capacity to about 600 GW – an expansion that in terms of wind energy will concentrate mainly on the north.

Mike Blicker: The advantages are already hinted at in Hans Schäfers’ responses. First and foremost, an electricity bidding zone split would massively reduce the enormously high redispatch costs. A split would also have massive implications for sector coupling: with cheap electricity in the north, green hydrogen could be produced close to the point of production, which would directly reduce the price of hydrogen.

EEHH: This brings us conveniently to the next question: from the point of view of the Northern German Living Lab, do we already have studies, modelling or project results that provide indications of how an electricity bidding zone split would affect electricity and hydrogen prices? And what is the position of the Northern German Living Lab (NRL) in this debate?

Mike Blicker: Most studies and also our project partners assume that the electricity price in the north would fall in the event of a split into two or more bidding zones. This is crucial for hydrogen production because the price of electricity directly influences the price of hydrogen. In addition, flexible operation would be possible, especially for PEM electrolysis, but also for modern alkaline electrolysers, which would enable better utilisation of temporarily low electricity prices. In the event of a split, low electricity prices would occur even more frequently in northern Germany and thus more hydrogen could be produced at a lower price.

A second aspect that should not be ignored is regulation. In the delegated act, the European Commission has stipulated that hydrogen is only considered sustainable or RNFBO (renewable fuel of non-biological origin)-compliant if the electricity used for its generation comes from renewable energies and can be clearly assigned to hydrogen production both temporally and geographically. With regard to the aspect of local proximity, which is legally defined by the bidding zone, a Germany-wide bidding zone is beneficial, but the temporal or plant-specific proof currently leads to cost increases. In the NRL, we have surveys that assume that the price per kilogram of hydrogen is one to two euros higher solely due to the specifications on how the electricity must be purchased (power purchase agreements – PPAs). If there were a separate electricity bidding zone for northern Germany or the Hamburg metropolitan region, these costly green electricity and certification procedures could be omitted, because in such a zone the share of renewables has already exceeded 90 percent in the last three years. The delegated act would then classify the electricity used there as green electricity, without the need for complicated and expensive PPAs: a significant lever for the price.

EEHH: What specific impact on price would regional electricity bidding zones have for consumers?

Prof. Dr Hans Schäfers: Reduced costs for redispatch directly relieve grid charges and thus electricity costs for all consumers. No matter where they are on the net. Whether there would also be regional differences in electricity prices depends on how the suppliers position themselves in the new electricity markets. Traditionally, the end-customer price is usually calculated as a mixed price of various purchasing strategies that are intended to buffer the risk of electricity price fluctuations for the end customer. This also stretches across different electricity price zones. But in principle, there would probably initially be a tendency towards somewhat cheaper electricity prices in the north and somewhat more expensive ones in the south.

EEHH: What would be the consequences of a regionally differentiated electricity price for the hydrogen market and could it strengthen Germany’s competitiveness as a whole?

Mike Blicker: That is of course a far-reaching thesis. I have already outlined the positive developments on the hydrogen price due to lower electricity costs, greater utilisation of electrolysers and simplified H2 regulation. However, the hydrogen would also have to be transported from the place of production to the consumers. The expansion of the hydrogen core network and, if necessary, additional pipelines would be necessary for this, as the hydrogen can be produced in the north and also lands via the import ports.

However, regional electricity zones also provide price incentives for battery storage systems. These would then be built in grid areas where they are really needed. At present, there are few incentives for grid support when choosing the location of such storage systems. Regional electricity zones could thus benefit the electricity system and the whole of Germany. As far as hydrogen is concerned, however, only if the necessary pipeline infrastructure is established and hydrogen can also be delivered to the users. Compared to power lines, pipelines can transport significantly larger quantities of energy through the grid at lower prices via chemical energy sources, especially if old gas pipelines can be repurposed.

Prof. Dr Hans Schäfers: The NRL is of the opinion that the positive effects of regional electricity zones clearly outweigh the negative effects. We welcome more openness for this topic. If policymakers want to drive the energy transition forward through market mechanisms and reduce regulatory requirements, this is a tool that they ought not to rule out.

EEHH: Thank you very much for the insightful interview!