The German Electricity Market Needs Local Prices

ZEW President Achim Wambach, along with eleven renowned energy economists, is calling for the introduction of regional electricity pricing in Germany. The current practice of setting a uniform national electricity price ignores regional differences in supply and demand, leading to inefficient decisions and high costs. Introducing local electricity pricing could resolve these issues and create a more efficient and sustainable energy system. This guest article is by Achim Wambach, Lion Hirth (Hertie School and Neon), Axel Ockenfels (University of Cologne and MPI Bonn), Martin Bichler (TU Munich), Ottmar Edenhofer (PIK and TU Berlin), Veronika Grimm (University of Technology Nuremberg), Andreas Löschel (Ruhr University Bochum), Felix Matthes (Oeko-Institut), Christoph Maurer (Consentec and FAU Erlangen-Nuremberg), Karsten Neuhoff (DIW), Karen Pittel (Ifo), and Georg Zachmann (Bruegel).

In Germany, the capacity of the electricity grids is regularly stretched to its limits. The economic value of electricity then varies regionally: in areas where a lot of wind and solar power is generated, the economic value of electricity at those times is low. Often, it is even zero or negative, due to an excess supply of electricity. Accordingly, the price that would balance supply and demand in these regions would be very low. Conversely, in regions where high electricity consumption meets limited supply, electricity is very valuable, and the price that balances supply and demand is high. Therefore, electricity has a local value. Only if the electricity grid has enough capacity to balance supply and demand in all regions simultaneously, do regional differences in value disappear.

The German electricity market ignores these regional differences. Germany has a single price zone, which means that the price on the electricity exchange is always the same throughout the country, regardless of what the actual regional market-clearing prices are and how valuable electricity is in a particular location. The electricity market operates under the illusion that there is always sufficient transmission capacity. One reason for this market design is to avoid politically undesirable regional price inequalities – although there are already regional price differences today, for example, due to different grid charges (which are higher in regions with many wind and solar farms, where electricity should actually be cheaper). Given the major challenges facing the electricity market, this illusion cannot be maintained for much longer.

Because of the political mandate for a single national electricity price, all actors in the electricity market – electricity consumers, power plants, wind and solar farms, batteries and pumped-storage power plants, hydrogen producers, imports and exports – follow this price signal. As a result, decisions are often made that are physically impossible within the grid and economically absurd. For instance, if the electricity price on the exchange is moderately high, power plants and wind farms in northern Germany generate a lot of electricity, even though it cannot be transported to the consumption centres in the south. Meanwhile, gas-fired power stations in Bavaria sit idle, leaving local electricity demand unmet. And that is by no means all: pumped-storage power plants in the Black Forest pump water up the mountains despite the electricity shortage in southern Germany, and smart electric vehicles in Stuttgart charge their batteries because the visible price of electricity is low – when in reality, cheap wind power doesn’t actually reach Baden-Württemberg. What’s more, Germany exports electricity to France and Switzerland because prices there are higher, but is unable deliver the electricity to the border. At the same time, we import electricity from Sweden and Denmark due to the price signal, even though the lines in Lower Saxony are already overloaded by domestic production.

The north-south grid congestion in Germany can work both ways. Further expansion of solar energy in southern Germany could create the same problems in the opposite direction, with excess supply in Bavaria or Baden-Württemberg.

Since physics does not adjust to the desire for a uniform national electricity price, grid operators have to painstakingly correct all these (wrong) decisions through a process known as redispatch: power plants in southern Germany are ordered to ramp up, wind farms in the North Sea are curtailed. The former are paid more for production than the uniform electricity price, the latter are paid for not producing. One problem is that many installations, such as batteries, electric vehicles or small solar systems, are out of reach of grid operators. They continue to behave in line with the uniform exchange price for electricity. They also have very limited ability to adjust exports and imports. Redispatch is a costly and complex repair in the electricity market, which ultimately leads to different local compensation for supply – but through the back door.

This redispatch robs Germany of the efficiency and effectiveness of a market-based price control. Instead of laboriously and imperfectly fixing a market intervention that results in physically impossible decisions, the path should be cleared for electricity pricing that balances supply and demand regionally and thus reflects the local value of electricity. The electricity price on the exchange should be higher where there is high demand and lower where there is an oversupply at that moment. These conditions change by the minute, so price differences dynamically vary. Based on such pricing, power plants, storage, imports and exports, as well as intelligent electricity consumption, can be optimised to support the grid and lower average electricity costs.

Local electricity pricing also means that new industrial investments can benefit from the local surplus of green electricity. Those who invest in hydrogen production, data centres or green steel factories in Mecklenburg today always pay the national price, even if electricity is locally abundant and the wind farm next door is curtailed. Because investors in Germany do not get cheap electricity, they are increasingly drawn abroad: to Sweden, for example, where regional electricity pricing has long been in place.

The decision on local electricity pricing should therefore be taken sooner rather than later. With the capacity market, a crucial decision will be taken in the next few months on the design of the electricity market for the coming years and decades. The government may be tempted to ignore the factual existence of regional electricity markets in Germany and the need for local prices by dictating the location choice of new power plants within the new capacity market. But even if it succeeded in efficiently regulating location decisions, power plant operation, storage, consumers and import/export would remain blind to local conditions as local market conditions are not reflected in the price. Since batteries, electric vehicles and power-to-heat systems then threaten to overload the grid, there is a risk that they will be tightly regulated or completely curtailed – even though it is precisely this flexibility that we urgently need for the energy system of the future. However, if the government signals that it will switch to local pricing in the future, investors will build at efficient locations. Otherwise, the problems of the electricity market will merely be patched up, the financing of the capacity market will become more expensive, and the goal of a secure, renewable and affordable electricity supply will move further away.

More and more countries are taking this path. In Europe, Denmark, Norway, Sweden and Italy have long had smaller regional price zones rather than a single national one. In the US, many electricity markets first divided their price zones and then introduced even more local prices at the grid node level (‘nodal pricing’). Germany has also already mastered a zone division: we had a common bidding zone with Austria for 17 years, which was then separated in 2018. Viable concepts for the necessary adjustments to the forward market for local prices have long been on the table. Distributional issues, such as those that may arise between electricity-intensive industry in the south and offshore wind farm operators in the north, can also be resolved without undermining the market mechanism. The differences in annual average prices are likely to be moderate anyway – 5 to 20 €/MWh according to various studies – and thus lower than the differences in distribution network charges that exist today. Moreover, introducing local prices lowers the grid charges that finance redispatch.

Much more relevant for the efficient operation of the energy system than average prices are the differences in individual quarter hours, as these set the incentives for grid-friendly operation of flexible plants. Only local prices in the electricity market can sensibly translate the dynamics of the electricity grid into flexibility incentives; alternative control instruments are not convincing. Such price differences are also crucial for efficient investment decisions, flexibility decisions, innovation incentives and thus the resilience of the electricity market in the transition to a sustainable electricity system.

The introduction of local pricing is no substitute for an ambitious and rapid expansion of electricity grids. But this alone will not be enough. If Germany is to achieve its ambitious economic and climate policy goals, it needs an electricity market design that reflects the physical and economic reality. And that includes local prices in the electricity market.

This opinion was first published as a guest article in the FAZ (in German language).