In January 2022, the Federal Network Agency initiated a procedure (pursuant to Section 29 (1) EnWG in conjunction with Sections 13j (1) sentence 2, 13a (2) EnWG) to determine the appropriate financial compensation for redispatch measures. Kyon Energy has taken this opportunity to participate in the public debate as part of the consultation process. The following topics were covered in our statement in order to contribute to a resilient and energy-turnaround-capable grid:
Battery storage systems play an essential role in the energy transition. They can compensate for fluctuations and forecasting errors in electricity generation from renewable energies in the short term and have a stabilizing effect in the short-term period of interest for the grid. They are already making an important contribution to grid stability and the integration of renewable energies.
However, the current legal and regulatory framework conditions are still hampering their grid-friendly use, and many of the technical potentials of storage systems remain unused. Without adequate business models and a market model that enables energy storage facilities to operate both profitably and in a way that serves the grid, it will not be possible to achieve the expansion targets set out in the grid development plan. Essentially, energy storage facilities have the potential to contribute far more to the grid infrastructure than is the case under the current market design and remuneration mechanisms.
As a result, the Kyon Energy proposal therefore aims to completely redesign the remuneration mechanisms with regard to energy storage systems. In Kyon Energy's view, this is necessary because, on the one hand, the current procedure leaves the extensive potential for grid-supportive use of market-based storage systems untapped and, on the other hand, the current cost determination of generation expenses and opportunities does not do justice to the complexity of large-scale battery storage systems. In order to do justice to the characteristics of large-scale battery storage systems - in particular dynamic schedule adjustments and simultaneous use in several different markets - as well as the different grid topologies, a fundamental revision of the remuneration mechanism for storage systems (especially large-scale battery storage systems) in congestion management is required. At the same time, there is an acute need for action, if only because studies by Kyon Energy show that energy storage systems have incentives to exacerbate existing congestion ("strategic bidding behavior") in the currently envisaged cost-based procedure. The risk of strategic bidding behavior is actually the central argument that is often put forward against market mechanisms in redispatch ("flexibility markets"). However, it also applies to cost-based redispatch with incorrect cost determination. This results in additional costs for redispatch, which could be significantly decimated or completely prevented by a proper incentive system for battery storage. From Kyon Energy's point of view, the problem is of a fundamental nature and cannot be solved in a cost-based redispatch, which is why a price-based procedure is proposed below for energy storage systems, which eliminates the incentives for behavior that exacerbates congestion.
An example of the redispatch remuneration of a typical 'Nord' energy storage system with negative redispatch demand is presented below. An exemplary battery storage system as built by Kyon Energy and connected to the public grid is considered. As is generally known, grid bottlenecks often occur in northern and eastern Germany when there is a high feed-in of electrical energy from wind turbines when attempts are made to transport this electrical energy to high-consumption regions in the south and west of the country.
The effects of a market-based battery storage system are described below as an example. Congestion management is a continuously rolling process that adapts dynamically to generation and consumption forecasts. These calculations are therefore exemplary and should not be understood as a general cost basis for the redispatch of energy storage systems. This example is intended to illustrate the limitations of the cost-based approach without claiming to be universally valid. To anticipate the result: It shows that the current approach for determining a cost basis for redispatch measures is not suitable for battery storage.
In the initial situation of the example, an energy storage system is considered that is located in the immediate vicinity of renewable energy generation plants. Two typical effects can be observed in this constellation when there is a surplus of renewable energy: The intraday market price is low, and the local grid infrastructure in the immediate vicinity of the storage facility is overloaded, as is the transmission grid to the major consumption centers. The storage facility, which aligns its charging and discharging behavior with the prices on the intraday market, therefore plans to charge itself during times of grid congestion. In the attached diagram, this happens in the period marked in turquoise.
Based on the signal from the electricity market, surplus electricity, which would be curtailed in case of doubt due to grid overload, would be temporarily stored. The original schedule therefore provides for congestion-reducing behavior of the energy storage system.
However, this market-based grid-relieving behavior can be overridden by the existing regulatory framework for congestion management. In principle, all players who have to participate in redispatch must report their redispatch assets to the grid operator on an ongoing basis. A storage facility that, driven by low market prices, charges with its entire procurement capacity has no additional charging capacity - it cannot be used for a negative redispatch measure (i.e. further charging) and its negative redispatch capacity is zero.
Without the false incentive effect of the redispatch remuneration, the storage facility would regularly recharge itself with energy purchased on the intraday market. This would incur costs for the storage operator in the amount of the purchased energy.
As the storage system has no redispatch capacity in the initial situation, its charging behavior corresponds to its normal cycle behavior on the market. In other words, the energy storage system charges at full load when a lot of electricity is available in the grid (this is the case because the storage system is on the "right" side of the congestion here) and pays the market price for this. Charging the storage system during the congestion via the intraday market therefore leads to congestion relief for grid operators and costs for the storage system operator. The price signal on the intraday electricity market leads to congestion avoidance (grid-friendly schedule). In our numerical example:
Cash flow outside of redispatch (alleviating congestion)= approx. -550 EUR (costs incurred by the storage operator)
The crucial point: If the storage facility had redispatch assets in the initial situation, it would be remunerated for a redispatch measure instead of bearing the costs for its grid-supporting behavior, whereby this remuneration is "on a cost basis". This becomes a problem as soon as the "cost basis" is determined incorrectly. This is because the energy storage system then has an undesirable incentive from a system perspective to deviate from its regular charging behavior.
Instead of behaving in accordance with the optimal charging time, which is determined via the intraday market signal, if the cost basis of the redispatch remuneration is determined too generously, there is a tendency to remain inactive or even to display a hypothetical storage schedule in which the charging movement is replaced by a discharging movement. This behavior doubles the redispatch capacity of the storage facility, but at the same time increases the total redispatch requirement for the grid operator. This congestion exacerbating behavior is due to a false incentive effect, which can be caused by the current cost determination of redispatch.
A call in redispatch according to the current remuneration structures is often more lucrative for the storage operator than a charging process via the intraday market. This is due to the fact that the costs are often mapped incorrectly. In the specific example, the storage operator weighs up the payment for the purchased electricity on the intraday market against the remuneration for its use in redispatch. For the use in redispatch, however, he would be entitled to compensation for the "pro rata value consumption" resulting from the wear and tear of the battery. In the case described, the compensation for use in redispatch corresponds not only to the additional charging process, but also to the lack of discharge of the storage system, which was only sought to maximize profits in the event of a bottleneck. This results in a doubling of the redispatch assets and subsequently also the remuneration for the omitted charging and additional discharging (including the respective pro rata value consumptions).
This strategic scheduling in order to benefit as much as possible from the redispatch remuneration can lead to the storage facility sometimes displaying behavior that exacerbates congestion. It only reports this schedule in order to maximize its redispatch assets and thus continue to benefit from the remuneration structure as provided for in the cost-based approach. Such behavior would not be sought by a storage facility that is not part of the redispatch.
A corresponding, strategically selected schedule adjustment is described in the diagram below.
The reason for these disincentives in the design of the storage system is not fundamentally linked to energy storage as a technology. Rather, a cost-based approach, which is currently being used, is unsuitable for leveraging the potential for economically favorable congestion management through storage, despite deviating requirements from the legislator. The reasons why such an approach seems unsuitable for battery storage systems are explained below.
Cash flow in the event of unloading and no loading movement as part of redispatch = approx. 580 EUR (profit generated by storage)
The current remuneration approach for redispatch by the BNetzA creates false incentives for the use of battery storage systems to avoid grid congestion. This results in higher overall congestion management costs.
In principle, the proposed cost calculation is based on three partial costs - the generation costs, the proportionate value consumption and the opportunity costs. In their current form of calculation, however, all three appear unsuitable to even approximately reflect the costs incurred by storage system operators.
The cost determination for the remuneration of redispatch measures proves to be inadequate with regard to the complex reality of large-scale battery storage. For example, the calculation of generation costs is based solely on daily shadow prices from the intra-day opening auction. However, modern large-scale battery storage systems operate on several energy markets simultaneously, such as the FCR market, the aFRR market (also short-term in the aFRR energy market up to 30 minutes before the supply period), and not just on the intra-day opening auction. This overarching trade and the dynamic scheduling of battery storage systems are neglected.
At the same time, the restriction of the number of cycles leads to difficulties in calculating the proportionate value consumption, as cycles are not additionally completed, but merely postponed. After a redispatch measure has been carried out, the storage system does not return to the initial state before the measure, but adjusts the schedule according to the new market conditions and the current state of charge (SOC).
The determination of opportunity costs is also considerably more complex than previously assumed in the WEBER approach1 . For example, 'costs for loss of flexibility' are not mapped on different markets at the same time and in view of the rolling procedure for determining the timetable (see BK8-18-0007-A, Annex 2: Weber Report dated 11.08.2015). Therefore, the determination of opportunity costs due to loss of flexibility is also not fully mapped.
These listed weaknesses of the cost-based approach can have some negative effects. For example, the integration of storage facilities into congestion management according to the current specifications cannot increase the potential for cost reduction for grid operators and thus lead to a reduction in the grid fees paid by consumers. The growing costs of redispatch measures represent an increasing economic problem. In 2022, the costs amounted to €4.2 billion. They are passed on to electricity consumers.
There is a fundamental problem with the current cost-based procedure for large-scale battery storage systems: The conflict between locally different grid topologies and a uniform price zone, together with the dynamic schedules of energy storage systems ("shifters" within the meaning of Section 3 No. 15d EnWG, such as grid-connected battery storage systems) on different markets, makes it impossible to determine a uniform and highly simplified cost structure and opens up potential for strategic bidding behavior.
The integration of energy storage facilities operated on the market as an additional component in the existing congestion management system must therefore be designed in such a way that the potential for strategic behavior that exists in the current, cost-based procedure is eliminated and incentives for market-driven congestion-reducing behavior are created at the same time. To this end, the cost-based redispatch procedure for energy storage facilities must be replaced by a price-based procedure. Insofar as a price-based procedure can rule out strategic behavior that exacerbates congestion, such a procedure is already required by law in accordance with Section 14c EnWG, at least in the distribution grids, and should also be applied in the transmission grids.
We are therefore introducing the following concepts for demand-based pricing in redispatch:
- Proposal 1 - static pricing: bilateral agreement of prices and quantities with the local grid operator, e.g. as part of the grid connection agreement
- Proposal 2 - dynamic pricing and schedule design taking into account the local grid topology: integration of flexibilities into the existing redispatch procedure with a simultaneous incentive for congestion-oriented schedule design
One option with rather low contractual complexity but with increased complexity in the procedural handling for storage operators and grid operators is to define a storage schedule in advance for each storage location and the predictable local grid congestion, which has a congestion-reducing effect. At the time of the grid connection contract, a certain quota of full load hours (in both positive and negative redispatch directions as required) is agreed for this schedule. These are remunerated to the storage system operator according to a price that is also determined at the beginning. Within the remuneration structure, a distinction is made between curtailment and activation of the storage facility.
Operational implementation of the process
The transmission of redispatch assets and the price of the measures takes place via the usual technical interface RAIDA, participation in redispatch measures takes place on call. The price for participation in redispatch measures is determined by the storage system operator. The cost basis is not determined by third parties.
Reducing the costs of congestion management for grid operators
It is to be expected that by voluntarily postponing the charging and discharging movements, congestion relief can be provided more cost-effectively from the grid operator's point of view. Due to the severely limited number of daily cycles, it is almost impossible for the storage facility to run additional cycles as part of congestion management. Therefore, the price determination of the redispatch measure for storage operators is based on opportunity costs. An accurate determination of the opportunity is significantly more complex than envisaged in Weber's simplified approach (see BK8-18-0007-A, Annex 2: Weber expert opinion of 11.08.2015). However, the responsibility for an accurate approximation lies with the storage operator.
Create incentives for grid-friendly behavior: Inclusion of local bottlenecks in original energy storage schedules
In order to ensure that the energy storage system provides a grid-supportive, congestion-reducing schedule, it undertakes to accept a certain quota of hours per year of curtailment down to zero without remuneration by the grid operator. In those periods in which the storage facility is curtailed by the grid operator without remuneration in order to prevent a worsening of congestion, a (later) price-based provision of a congestion-relieving schedule must be excluded at the same time.
A curtailment (prohibition of feed-in or feed-out in a direction that is harmful to the grid) restores the grid status without storage (use). The storage system thus has a high intrinsic incentive not to set a grid-damaging schedule from the outset in order to participate in the price-based procedure and realize profits there. The number of hours in which uncompensated curtailment is possible is regulated during the connection procedure, whereby a framework can be set by the Federal Network Agency.
The use of energy storage systems via dynamic pricing in a price-based remuneration system has many advantages:
→ Targeted selection of a location for storage development in congested areas in the immediate vicinity of renewable energy plants (in line with the requirements of the 2037 grid development plan)
→ Reduction in demand and overall costs for congestion management through the use of battery storage
→ Cost-efficient use of existing grid infrastructure
In order to make sensible use of the potential of battery storage in congestion management, their remuneration for redispatch measures should not be based on cost calculations, but should be based on a price-based procedure. This requires the consideration of local grid topologies in the grid connection procedure between grid and storage operators. The grid operators are dependent on storage facilities and are responsible for providing the necessary 23.7 GW of storage capacity in the energy system by 2037.
For project planners and operators of battery storage systems, the proposed regulatory adjustments will open up new business models and revenue potential. At the same time, the costs for congestion management can be reduced, thus relieving the burden on electricity consumers. The provision of grid connections at grid-relevant locations also increases the total volume of storage that can be added to the grid. This creates further economic benefits, even in times of congestion, by stabilizing the electricity markets and reducing the costs of balancing power and the wholesale market. A win-win situation! Accordingly, a price-based mechanism for the use of (large-scale battery) storage systems in congestion management should now be introduced.
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