The tension between investment incentives and competitive electricity prices

Electricity consumption in Germany remained largely stable between 2000 and 2017. Gross annual consumption fluctuated between 575 and 620 terawatt hours (TWh) depending on economic development and weather among other factors. During this period, no clear upward or downward trends could be observed. Electricity consumption has fallen since 2018. This is particularly true for the years 2022 and 2023. Electricity consumption in 2023 was around 8% lower than in 2021, mainly due to production declines in the energy-intensive industries. Even so, industry still accounted for 43% of the total electricity demand in 2023. Private households and the commercial/trade/services sectors each accounted for a good one quarter of electricity consumption in 2023. The transport sector accounted for just 3%.

Profiles for electricity demand fluctuate greatly depending on the time of day. There are also significant differences between working days on the one hand and weekends and public holidays on the other. In contrast, seasonal fluctuations during the year were less pronounced in the past, even though demand tended to be somewhat higher in winter than in summer. According to the Federal Network Agency, the peak load in Germany, which is usually reached in the late afternoon or early evening of a working day between November and February, has developed as follows in recent years for the DE/LU market area:

Reduced industrial production is likely to be one of the main reasons for the decline recorded since 2021.

The situation is expected to change in the future (see Figures 1 and 5).

The decarbonization of energy supply targeted by 2045 is to be achieved in particular through increased electrification. Electricity generated with low CO₂ emissions is to replace fossil fuels both in industry and in private households, commercial/trade/services and transport. This political strategy is to be implemented through process innovations in industry, the increased use of electric heat pumps in the building sector and electromobility.

As a result, electricity consumption in Germany is expected to grow in future. The Federal Ministry for Economic Affairs and Climate Protection expects consumption to rise to between 680 and 750 TWh by 2030. In the Energy Transition Outlook Germany, published in February 2025, DNV forecasts a somewhat more modest increase in electricity consumption in the coming years. According to this forecast, the electricity consumption, mentioned by the Federal Ministry for Economic Affairs and Climate Protection for 2030, will only be achieved in the second half of the 2030s. For 2050, DNV puts electricity consumption in Germany at 896 TWh compared to around 490 TWh in 2024.

One of the applications that will increase electricity demand in the future is heat pumps for heating. According to the assumptions made in the Electricity Network Development Plan of the Federal Network Agency (Bundesnetzagentur - BNetzA), electricity consumption will increase from 4.5 TWh in 2022 to around 100 TWh by 2045 as a result of this development.

In the transport sector, electricity consumption rose from practically zero to around 2.5 TWh between 2014 and 2022. According to the German government's coalition agreement of 2021, the electric vehicle fleet of 2.5 million electrically powered cars as of 1 July 2024 should reach around 15 million cars by 2030. The Electricity Grid Development Plan therefore identifies electricity demand for electromobility of 100 to 150 TWh in 2045. As the Expert Commission on Energy Transition Monitoring explains in its report published in June 2024, "it must be taken into account that the power at which electric vehicles are charged is often very high, i.e. the required energy is drawn over a short period of time and could lead to high load peaks if charging is not coordinated, e.g. via price signals (and possibly also via reductions in accordance with Section 14a EnWG)."

In industry, the targeted decarbonization can be achieved through the direct use of renewable electricity or indirectly through the use of hydrogen produced by electrolysis. In the scenarios of the Electricity Network Development Plan, the electricity demand of industry is expected to increase by at least 100 TWh (lower limit) by 2045. The electricity demand for electrolysis, which is currently still negligible, is estimated to be at least 100 TWh by 2037 and more than 200 TWh by 2045.

On the other hand, there are also recognizable factors that could dampen future electricity consumption in industry. The BASF company can be cited as an example. In 2021, BASF consumed 6.0 TWh of electricity at its main site in Ludwigshafen alone. That is as much as the combined demand of all households in Hamburg, Duisburg and Munich. For 2022, BASF's electricity consumption at the Ludwigshafen site will be 5.3 TWh and for 2023 only 4.5 TWh, a reduction of 25% in two years.

With the increased electrification of heating in buildings, transport and industrial processes, a reversal of the peak load trend seen in recent years can be expected. According to DNV, the peak load in electricity demand, which was between 75 and 90 GW between 2000 and 2024, will increase to around 100 GW by 2035 and to around 135 GW by 2050.

In the past, there was sufficient availability of dispatchable power plant capacity in Germany. The net installed capacity of conventional power plants alone, i.e. plants based on nuclear energy, lignite, hard coal, natural gas, pump storage and mineral oil, totalled around 100 GW between 2000 and 2010. Even taking into account planned maintenance, unforeseen outages and the necessary reserve for system services, these conventional plants alone ensured that supply was guaranteed at all times. Fluctuations in demand and the increase in intermittent electricity supply could be balanced by the flexible operation of the existing coal and gas-fired power plants. The existing biomass plants also contribute to dispatchable output and the available pumped storage facilities can also cover short-term peaks in demand.

Since the beginning of the last decade, however, dispatchable capacity has steadily declined. The first cuts were made with the decommissioning of eight nuclear power plants in 2011 following the reactor disaster in Fukushima. This was followed by the gradual shutdown of the nine remaining nuclear power plants by April 2023, removing 20.5 GW of nuclear power capacity from the grid since the end of 2010. As part of the decision to phase out coal by 2038 at the latest, a total of almost 33 GW is to be decommissioned. By the end of 2023, the capacity of lignite and hard coal-fired power plants was already 11.9 GW lower than in 2010, compared to only 7.3 GW of additional electricity generation capacity based on natural gas and a limited expansion of battery storage. If we also include pumped storage, including those existing plants abroad that feed directly into the German electricity grid and power plants based on other energy sources such as waste, the conventional electricity generation capacity as of November 2024 is around 89.7 GW. Market-driven investments in secure capacity have been limited over the last ten years. This fact illustrates that the political expectation that the energy-only market 2.0 would provide incentives for the construction of new secure capacity has not been fulfilled.

In contrast, there has been a strong expansion of wind and photovoltaic systems. As of December, 2024, the installed capacity of wind power plants was 72.8 GW and of PV systems 99.2 GW. Including biomass, hydro and geothermal plants, the capacity of renewable energy plants, at around 189 GW, is now twice as high as the conventional generation capacity of 89.7 GW (Table 1). The total net installed electrical generation capacity is therefore three times higher than the currently expected annual peak load.

According to the transmission system operators, the guaranteed capacity available at the time of the annual peak load for conventional power plants is around 90%. In contrast, this guarantee is less than 10% for wind energy and zero for solar energy. A significantly higher availability can be assumed for biomass and hydropower plants at the time of peak load, which at least approximates to the situation for conventional energy sources (Figure 2). Taking these restrictions into account, the capacity of the entire electricity generation fleet in Germany that can be categorized as secure can be estimated at 92.3 GW (Figure 3).

According to the Federal Network Agency, a further 4.68 GW of conventional capacity, primarily based on hard coal, will be decommissioned by the end of 2027. The construction of new conventional plants is estimated at 2.68 GW for the period up to the end of 2027, mainly being natural gas plants. Conventional electricity generation capacity will therefore fall to 87.7 GW by the end of 2027 (Figure 4). This decline will continue in the following years as the phase-out of coal continues. In the event of a complete phase-out of hard coal and lignite by the end of this decade, which is being discussed by some politicians, dispatchable conventional capacity would fall to around 53 GW by 2030.¹ As a result, the secure capacity will decrease significantly by 2027 and even more so thereafter as the coal phase-out continues.

Germany is closely linked to its neighbors in the electricity sector via cross-border interconnectors. According to the BNetzA monitoring report, 14.12 GW (17.78 GW) was reported to be the maximum import capacity (export capacity) in 2022. The existing internal electricity market offers the advantage that the plants with the lowest variable costs - regardless of their location - are used, as long as transmission capacities do not present a bottleneck. In recent decades, electricity trade with neighboring countries has regularly led to deliveries from Germany exceeding imports from neighboring countries. In 2023, Germany was a net importer of electricity for the first time in 20 years. The main reasons for this were the newly improved availability of French nuclear power plants and the fall in gas prices which improved the economics of power generation outside Germany's borders.

The extent to which Germany will be able to draw on generation capacity abroad in the future is questionable. Peak loads often do not occur at the same time in Europe. However, as the data from the Transparency Platform of the European Network of Transmission System Operators for Electricity (ENTSO-E) shows, the highest loads in all the countries connected to the German electricity supply system occur between November and February. Therefore, even an expansion of the cross-border transmission system offers no guarantee that dispatchable power abroad can be utilized for supply in Germany. In addition, there are uncertainties regarding the availability of nuclear power plants in France, as the situation in 2022 has shown. Furthermore, not only in Germany, but also in most other European Union countries, a decline in dispatchable power plant capacity, especially coal-based, is to be expected.

The electricity system of the future faces a multitude of challenges. Growing demand for electricity must be met reliably at all times. Supply and demand structures need to be adapted. The infrastructure (grids and storage) must be capable of handling these changing conditions.

The structural development of supply and demand is not congruent. During the summer months, supply of electricity increases with the expansion of photovoltaics, while the development of demand lags behind (Figure 5). Consumers with their own electricity generation (PV) and storage systems have little need to purchase electricity from the grid, resulting in a surplus of electricity during the summer months. In contrast, the winter months are expected to see increased demand due to the electrification of the building sector.

Simulations published by ENTSO-E as part of the European Resource Adequacy Assessments for the year 2033 illustrate the possible developments towards greater seasonality in the load curve. At the same time, the residual load peak increases sharply compared to 2015 and 2023 despite the rapid expansion of renewable capacities on which the simulation is based (Table 2).

The existing energy-only market (EOM) will continue to be indispensable for system control in the future to efficiently manage a complex system with many players and decentralized assets. In this respect, a new market design must not only be suitable for current and future generation technologies, but must also provide market signals for energy storage and demand response. However, the risks for investors are increasing as scarcity signals in the market are expected to materialize mostly during the winter months. For investment decisions in the new, dispatchable power plants that are necessary to avoid shortages, the introduction of capacity payments is essential. Capacity mechanisms should be organized on a competitive and technology-neutral basis via tenders. This will establish an insurance premium for ancillary services that covers part of the investment and thus reduces the risk premiums for investors. Bespoke mechanisms can be realized in the short term, as it takes around six years to plan, approve and build gas-fired power plants.

In addition to the construction of natural gas power plants suitable for the future use of hydrogen, the expansion of energy storage facilities is necessary. For storage facilities, a basic distinction can be made between large storage facilities (pumped storage hydropower plants (PSH) and large battery storage facilities) and small storage facilities (commercial storage facilities, domestic installations and regenerative electric vehicles). As outlined in the BMWK electricity storage strategy, PSHs and battery storage systems (large batteries and decentralized home storage systems) are currently the most important categories for short term storage. The feed-in durations for PSHs are typically at most four hours in Germany, with longer feed-in durations being quite rare. There are currently around 30 PSHs installed in Germany with a capacity of around 24 GWh and a maximum output of around 6 GW. In addition, PSHs from Luxembourg and Austria with a capacity of 15 GWh and an output of 3.6 GW feed directly into the German grid. At 11 GWh, the capacity of the battery storage systems (as of December 2023) is still lower than the capacity of the PSHs. However, at 7 GW, battery storage systems already have a higher capacity than the PSHs installed in Germany. Battery storage systems currently have a maximum feed-in capacity of typically two hours. To displace a gas-fired power plant that runs at 800 MW base load for ten hours at night, a massive 4,000 MW of battery storage would be required with a capacity of 8,000 MWh. Battery storage systems are therefore more suitable for very short-term decoupling of generation and consumption as well as ancillary services for grid infrastructure.

In addition to supply-side measures, improved utilization and the creation of additional options for adapting demand to the electricity supply (demand-side management) are among the key flexibility options. Load management can be used to ensure that electricity is consumed when a large supply of electricity is available, e.g. during periods of strong winds. Variable tariffs can make such "load shifting" financially worthwhile for the end consumer. By controlling the consumption side, the maximum load and thus the need for secure capacity can be reduced. New technologies, such as smart meters, can help improve the conditions for keeping generation and consumption in balance. Such a balance, which is needed to guarantee the target frequency of 50 Hz, is essential for maintaining system security. Industry's economically viable load reduction potential is projected to be 15.6 GW for the year 2030 in a report commissioned by the BMWK. The Federal Network Agency came to a similar conclusion in its report on monitoring the security of electricity supply for 2031, which was presented at the beginning of 2023. According to this report, industrial processes and cross-sector technologies could supply 8 GW of curtailable power and emergency power systems a further 4.5 GW.

Industry points out that the flexibility potential of its plants cannot always be fully utilized, as there are delivery obligations, for example, or plant operating modes and limits that must be respected (e.g. continuous 24/7 processes and minimum loads). This is taken into account by sensible market design: Flexibility is only utilized when prices give a signal to do so. It is not an imposed measure, but a behavioral response to the market. If the economic benefits of providing flexibility are too small for industrial plants, other sources of flexibility will have to be utilized. Industrial companies may also consider how they could upgrade their plants to participate in the flexibility markets.

If we look at the requirements for the further development of the electricity market, there are specific demands on politicians and policymakers that are needed in the short term, but within a long-term policy framework. It will be important to consider the interactions between the various measures.

In their election programs most parties see the energy transition as an important aspect, specifically energy prices for industry and consumers. For a new government it is very important to tackle the most relevant topics in a short term program and to develop a long term strategy to bring the energy transition to an economical, industrial and clean success story.

We are facing fundamental changes in the energy market. Flexibility will be the most important characteristic on both the demand and supply sides so that the trend towards increasingly volatile generation can continue to be matched with consumption in the future. Digitalization allows all market participants in the electricity system to be visible, so is a basic prerequisite for future grid stability. These two - flexibility and digitalization - must be swiftly materialized using appropriate policy measures.

On the supply side, it will be important to send the right investment signals for secure capacity, flexibility and seasonal storage. In principle, existing market mechanisms are excellent at facilitating quick decisions on plant deployment in a complex, international market with many players. However, they are not sufficient to advance all the required investment decisions and therefore should be supplemented by a centralized capacity market.

Flexibility is just as important on the demand side. The energy transition can only succeed by shifting electricity consumption to times of high electricity generation and by adding more electricity storage. Against this backdrop, price signals must reach consumers, both private and industrial.

Flexibility on both sides is the key to energy transition. It must therefore be at the center of the political debate. For too long, as renewable energy sources have grown to dominate, we have neglected to simultaneously expand the grid and develop short- and long-term energy storage solutions.

For an overall cost-efficient system, the policy measures described above are an important step towards a flexible, functioning market design fit for the future.