The Energy Transition in Europe needs flexibility to reduce costs
The European energy transition will require annual investments of about 379 billion € in the period between 2020 and 2030 to reach the EU goals for CO2-reduction, high shares of renewables in the electricity supply and energy efficiency.
These are huge costs to start with, but a recent report by the German Think Tank AgoraEnergiewende suggests that in a scenario for 2050 the costs will be much lower in a RES-based energy system compared to those in a fossil fuel-based system (see figure 1). The difference in costs between a renewable system and a coal fired system in 2050 in Germany could add up to more than 400 billion € annually (considering a very high CO2-price of 50/t). So in the long run, the investment into the energy transition is worth it.
Still, we want to keep the costs of the energy transition as low as possible. To achieve this, battery storage is one of the promising technological applications as it might help to accelerate the energy transition and at the same time reduce the overall costs of this process. The current prices for battery storage are too high for the mass market, but this is will change very soon. Especially, as not only Tesla has a giga factory for battery storage, but many other companies currently invest in battery giga factories as well (see figure 2). In 2016, large battery factories like the Tesla Giga factory produced a battery capacity of roughly 28 GWh. This capacity is planned to increase to 174 GWh till 2020.
The Battery Storage market in Europe and Germany
In Europe, the battery storage market consists of two primary segments: The costumer market and the provision of ancillary services for the networks.
The costumer market in Europe and especially Germany focuses on self-consumption: households (prosumers) use batteries to increase self-consumption from solar PV. This market is growing since 2014 in Germany.
The second market segment for battery storage targets the networks. For the electricity system, small and large grid-scale battery storages can provide flexibility that is needed to balance consumption and production from distributed renewable sources. Furthermore, (grid-scale) battery storages could provide ancillary services (like voltage- & frequency control) to the networks.
In 2015, first projects evolved with grid scale battery storages aiming at the balancing markets in Europe (10 MW Germany and the Netherlands, 31.5 MW in the US). More info on grid scale projects in the US and the EU can be found here.
Battery storages can provide their services to the networks via two different markets:
First, The balancing market that allows the transmission grid operators to balance short-term deviations between supply and demand. Thereby, the balancing market aims at frequency control. So far, only few battery storage operators participate in the balancing market in Germany, as this business case is not yet profitable. This is different in California, US. Here, battery storages are gaining relevance in frequency control due to specific regulations that we will discuss later in the post.
Second, there is the concept of (regional) flexibility markets which can become a future business case for battery storages. Flexibility on the distribution grid refers to the ability of different applications like heat-pumps, electric vehicles and battery storages to provide grid services like congestion management and voltage control for the network operators. Up until today, there is no market platform for network operators to make use of battery capacity connected to the grid for grid services other than frequency control via the balancing markets. This being even more remarkable as the network operator has a distinctive demand for ancillary services provided by flexibility in case of network congestion. In a recently published report, the German Energy Agency (dena) projected for the year 2030 that network congestions in Germany will add up to 3.5% of all operation hours. While this is not a large number, it still requires action by the network operator. We need to keep in mind that network congestion on the distribution grid level differs significantly between regions in Germany. Especially in the north-eastern and north-western areas of Germany, today’s congestion already comes close to the estimates for the German average in 2030. So even today there is demand for flexibility and we can expect that it will increase significantly in northern Germany within the next years as the girds capacity is at its limits.
Even though there exist different potential markets for grid-scale battery storages to address network needs, they do not provide enough revenue for battery storage operators to become profitable. At least, if the battery provider only aims at one market, which was the main strategy of battery providers and producers so far. However, current discussions focus on the potential of multi-use battery storage concepts.
Multi-use battery storage - the idea
Multi-use here stands for battery storages that provide their services for different markets or for markets and the regulated business of the network operators (for ancillary services) at the same time. Figure 3 illustrates the idea of multi-use battery storage concepts: Address different markets to combine revenues and become profitable.
A multi-use battery storage can take different forms. For example, one storage can address two different segments
- within one market, e.g. self-consumption and emergency power in the consumer market
- in two different markets, e.g. self-consumption in the costumer market and frequency-control in the balancing market
Similar to studies by EPRI and the RMI for the US and by SBC for the UK, a recent study by the German energy Agency (dena) shows for the German market that there is a potential business case for Multi-use battery storage. The dena study focuses on six use cases. While four use cases describe the multi-use of battery storage in different markets, two use-cases investigate the economic potential of battery storage systems that participate in markets and provide network ancillary services for the network operators. From an institutional perspective, the biggest challenge for all of the use cases is to set the right incentives for all actors involved in flexibility provision (storage) as well as in flexibility demand (markets, networks) to achieve an economically optimal solution. While optimality is always a theoretical concept, we can at least discuss how to define the incentives for battery storage operators to optimize their business case in an economically efficient way.
The institutional challenge - how to get the incentives right
When it comes to the multi-use applications of battery storages that involve the market and the networks, we need to address to different perspectives: Which incentive does the battery storage operator have to adapt its operation to the network needs (e.g. in case of congestion) and which incentive does the network operator have to make use of the flexibility provided by the battery storage?
The answer to the first part of this question differs between existing markets and the networks: The balancing and spot markets use price signals that change within the course of the day depending on supply and demand. For example, when the spot market sets a price for purchasing or selling 1 MWh of electricity within a specific hour of the day (every 15 minutes), this price signals to the battery storages when to buy and sell electricity. Additionally, the balancing market gives signals to the battery storages when to adapt their operation for balancing purposes (seconds to minutes). Both signals allow the battery storages to optimize their operation and revenue.
Dynamic network charges
The distribution network on the other hand has only very limited ability to provide price signals to the battery storage to incentivize the battery operators to adapt their operation to the network needs, e.g. in case of network congestion. This is one of the major obstacles for the active provision of flexibility to the networks by battery storages (and applies to other flexibilities). One approach do address this issue is a flexible (dynamic) adaptation of network charges. The network charges are used to recover the costs for network operation and are charged for every kWh consumed. So far, the network charges in Germany are static and do not differ in time or location (at least not within the network area of one distribution grid operator). However, dynamic network charges that differ with the level of load could be used to give an incentive to flexibility providers (lower network charges in times of low load and visa versa). So far, we have only few experiences with the effects of dynamic network charges in Germany, which is why the dena report suggests to start with a pilot project to evaluate the interdependencies and effects of dynamic network charges with other market signals.
Regional flexibility markets
In addition to dynamic network charges, the network operator could reimburse flexibility providers for their network-friendly behaviour via regional flexibility markets. These markets could be used to trade different products to the network operators. This approach has been discussed in the dena study as well. Furthermore, the largest German energy think-tank (Agora Energiewende) proposed in February 2017 to establish 20-40 of those regional flexibility markets in Germany to reduce the costs of the energy transition. Different concepts for regional flexibility markets will be evaluated in the SINTEG projects funded by the Federal Ministry of Economics and Innovation. For example, the enera project will develop a regional electricity market.
Incentive Regulation of the network operators
Addressing the second part of the question above is very even more challenging: How to we incentivize the (distribution) network operator to make use of flexibility?
While dynamic network charges and regional flexibility markets are tools to incentivize flexibility providers to adapt to the current status of the distribution grid, they do not have an influence on the network operators’ behaviour. Rather, if we want the network operator to apply tools like dynamic network charges or make other use of flexibility to reduce costs, this requires an adaption of the regulation scheme of the network operators. So far, the regulatory system in Germany incentivizes the distribution grid operators to prefer solutions with high investment costs (CAPEX) rather then operational approaches with high operation costs (OPEX). Basically, the proposed solutions like dynamic network charges and regional flexibility markets increase operational costs, as someone at the distribution grid operator needs to manage a system to operate the dynamic network charges or the coordination via a regional flexibility market. At the same time, these operational approaches intend to reduce the investment need by the network operator, which reduces CAPEX and thereby the revenue of the network operator given the current regulation scheme. This trade-off is known as the CAPEX-OPEX-problem. So far, regulators have not yet addressed this issue, which keeps dynamic network charges and regional flexibility markets limited to some demonstration projects.
Even if we set the incentives right, there are further obstacles for the multi-use of business cases that address both, markets and networks. Ruz and Pollitt discuss in detail the challenge for multi-use business models that arise from the unbundling regime in Europe. Basically, the idea of the unbundling process is to secure that the monopolies (DSO and TSO) do not use their market power to disturb the markets. Pollitt and Ruz show in their analysis that transaction costs for multi-use battery storage concepts will be very high, reducing the profitability of such approaches. This is nicely illustrate this challenge in greater detail based on the experiences from the UKPN Smart Network Storage Project here.
Regulation in California: Best practice?
Interestingly, California is facing the same challenges described above, even though the Californian market for multi-use battery storages is much more mature. Ruz and Pollittidentify five regulations by FERC and the State of California that are the key drivers for the multi-use battery market here. Most prominently, FERC (Order 755) defined a new rule for frequency control, increasing the revenue of fast-response assets. EPRI calculated in 2013 that this rule increased the cost/benefit ratio of battery storage systems by 18% (transmission) and 13% (distribution). The other FERC regulations further strengthened the position of battery storages by addressing Third-Party Provision for ancillary services and network planning by TSOs.
The real boost for the grid-scale battery market was a regulation issued by the Government of California. Based on the assembly bill 2514 the three largest utilities in California are required to procure 1325 MW of battery storages in 2020. Thereby, the market for battery storages gained significantly. Further details on the California case can be found here.
We can conclude that there is a large potential for battery storages in Germany and that multi-use applications can further increase the business case. However, especially at the intersection between the markets and the networks we need to adapt the institutional framework (dynamic network charges, regional flexibility markets, regulation of network operators) to allow smart grid applications to prosper. The case of California illustrates potential regulatory measures to support the battery market development. Driven by such an adaptation of the institutional framework we can expect the battery market to gain significant relevance in Germany as well.
So the question remains: Will we establish the right institutional framework in Germany and Europe to exploit the potential of battery technology for the energy transition and the development of smart grids?
What do you think?