Congestion Management: Redispatch 2.0 in International Comparison
The need for a targeted, rapid transformation of the German energy system is becoming abundantly clear. The decentralization of energy generation through the expansion of renewable energies leads to a debate about how grid and system stability will be ensured in the future. The integration of small-scale generation plants and consumers offers great potential. In Germany, the introduction of Redispatch 2.0 was an initial step toward exploiting this potential. A current point of discussion for the further design of the process is the integration of flexible loads, which are increasingly available due to the electrification of the mobility and heating sector. With a view to other countries, this article supplements the considerations on the design of the use of small-scale plants for congestion management with alternative approaches and discusses them with regard to the German energy system.
The German energy system is undergoing a transformation. In addition to the intended shutdown of large fossil and nuclear power plants, electrification in the industrial, heating and mobility sectors is also shifting their supply to the electricity sector. The result is a large number of new electrical consumers, which pose challenges for network operators in their operations management processes. On the other hand, advancing digitalization also enables new strategies for grid operation. Electric vehicles representing new components for grid and ancillary service processes due to their storage capacity could also play a central role. Consideration of the rapidly increasing registration figures for electric vehicles in Europe at present reinforces this thesis and simultaneously elucidates that the electrification of the mobility sector is a cross-border development . Consequently, in the context of the discussion being held in Germany about the procedural and technical implementation of the integration of electric vehicles into network and system service processes, it also makes sense to take a look across national borders. A Europe-wide consideration of this change can also be important for internationally active automotive and component manufacturers.
Other countries are confronted with similar challenges as Germany. In the European area, nations are subject to the same European regulations. The European Commission’s “Electricity Balancing Guideline” provides a common basis for designing processes to ensure system stability. The guideline aims to create a market through which transmission system operators (TSOs) can share the available resources. It also aims to include renewable energy (RE) plants as well as opportunities to intervene in consumption patterns. The target is to increase security of supply, limit emissions and reduce costs.  In addition, the “Regulation on Capacity Allocation and Congestion Management” lays down requirements for the coupling of short-term electricity trading markets in the EU and defines the procedure for calculating cross-border capacities.  The directives, which apply throughout Europe, have to be implemented by the member states at national level. Different approaches to ensure system stability are presented below, and their application in other countries is discussed.
Grid and ancillary services
In this article, grid and ancillary services are defined as follows:
- Grid services: Grid services are measures that serve (local) congestion relief in grid operations.
- Ancillary services: Ancillary services are defined as higher-level systemic measures that contribute to system stability in the context of frequency and voltage maintenance, such as the provision of frequency control.
Status quo and current discussion in Germany
According to the Energy Industry Act (§§ 13, 14 EnWG), electricity grid operators in Germany are obliged to ensure the security and reliability of the electricity supply in their grid. Suppose the day-ahead power forecasts by the TSOs indicate that grid congestion is expected due to planned dispatch. In that case, so-called “redispatch” measures are implemented to ensure grid stability and avoid grid congestion. This means that power plants in regions with high consumption are activated. At the same time, power plants that contribute to the creation of the grid bottleneck are instructed to reduce their output contrary to the originally planned dispatch. In the past, “classic” redispatch was carried out with large conventional power plants of 10 MW or more.
In contrast to conventional power plants, ramping up RE plants to increase feed -in is only possible to a limited extent. In order to avoid grid congestion, a curtailment of supply-dependent plants took place until September 30, 2021, within the framework of the so-called feed-in management (ger.: Einspeisemanagement), whereby corresponding compensation payments had to be made to the plant operators for the resulting outage work . The feed-in management was replaced by the amended Grid Expansion Acceleration Act (NABEG 2.0) and transferred to the currently regulated Redispatch 2.0. This obliges plants with a capacity of 100 kW or more to participate. In addition to previously conventional generation plants with 100 kW or more capacity, the available flexibility potential now includes RE plants and combined heat and power plants with capacities between 100 kW and 10 MW. For plants with less than 100 kW, participation in redispatch is mandatory, provided the grid operator can control them. This increases the number of plants participating in redispatch from about 80 to about 60,000. Capacity from electric storage systems or electric cars, as well as demand-side potential is not included and is currently not available for redispatch. The financial compensation in this model of self-cost-based redispatch only remunerates the lost revenue due to redispatch. 
Section 14a: controllable consumption devices
Section 14a of the Energy Industry Act (EnWG) is another instrument for ensuring efficient grid operation and successful conversion and expansion of the distribution grid. According to its design, this is primarily intended to regulate the controllability of flexibilities in the lowest levels of the distribution grid by the distribution grid operators . The aim is to reduce the necessary grid expansion resulting from integrating RE plants and the electrification of the mobility and heat sectors. By making flexibilities controllable, the distribution grids would thus not have to be expanded for times of absolute peak load. Various stakeholders controversially discuss concepts for the design. Questions concerning the definition of controllable plants, the control processes, the type, degree and duration of control, financial incentives and the technology that will be used, are currently the main discussion point.
From the perspective of the grid operators, decentralized flexibilities with connected loads of less than 100 kW also offer the potential to generate added value for redispatch measures in terms of energy and grid management, over and above possible § 14a control. This third step in the evolution of redispatch is consequently called “Redispatch 3.0”. A central challenge of the Redispatch 2.0 is the efficient exchange of information between transmission and distribution system operators as well as communication with generation plants and consumers. This intensifies the market-based “Redispatch 3.0” concept due to the large number of controllable power generation and consumption units that could be integrated into the process. In particular, the development of a cloud-based and BSI-compliant IoT alternative to classic grid control systems is targeted in this concept. In the future, the smallest systems not available in the communication cascade today will be connected via the CLS functions of the smart metering systems installed in the smart meter rollout.  The implementation of the concepts for the further development of Redispatch 2.0 is being piloted in various research projects, such as the “Redispatch 3.0” funding project of the same name . Already realized concepts are the flexibility markets in the SINTEG project “C/sells”, which also use demand-side flexibility for grid congestion management. The “Altdorfer Flexmarkt” developed in the project had already integrated micro-flexibilities (e.g., heat pumps) into a flexibility platform .
Market-based models are an alternative to cost-based redispatch. In the context of the grid-serving use of flexibility based on market-side price signals at the transmission grid level, one speaks of market-based redispatch. The terms “flexibility market” or “smart market” are also common at the distribution grid level.
How does market-based redispatch work?
All players can participate voluntarily in a market-based redispatch and make their flexibility available by bidding. When used, a compensation payment is made .
Market-based redispatch is intended to offer players additional revenue potential and thus motivate them to participate. In addition, other, especially small-scale flexibilities such as loads, distributed generators or storage facilities, can increase the flexibility potential . Furthermore, a better spatial distribution is achieved by integrating several plants, whereby plants with a higher sensitivity to a specific bottleneck can be used in a targeted manner. The higher number of market participants can lead to more competition between the players if there is a sufficient monetary incentive. In addition, pricing becomes more transparent. On the downside, problems such as strategic bidding behavior or the exercise of market power can arise. For a more detailed consideration of these issues, please refer to . Various concepts of how a market-based redispatch or flexibility market can be designed, have been developed and tested, for example, in the “C/sells” project as part of the SINTEG funding program .
Price signals: Zonal and nodal pricing
Another alternative for raising flexibility potentials, which is applied in some countries, is price incentives. Depending on the subdivision of the network area, this is referred to as “zonal pricing” or “nodal pricing”. With zonal pricing, the grid is divided into different bidding zones, resulting in zonal electricity prices. In the case of nodal pricing or locational marginal pricing, the prices are determined with a higher spatial resolution for each grid node.
By dividing the grid area into different bidding zones, various prices can arise for different grid areas, with one price applying to the entire bidding zone. The resulting zonal prices map congestion between zones and can counteract structurally induced network bottlenecks, such as the north-south congestion in Germany. In the event of congestion, prices rise, for example, in the zone after the congestion, making generation more profitable and consumption more expensive, and fall in the zone before the congestion, making generation less attractive and consumption less expensive. As a result, the congested line is relieved. Furthermore, this provides regional investment incentives that can prevent structural congestion between bidding zones in the long run .
In nodal pricing, the optimal deployment of generators and consumers is mapped in monetary terms, considering the grid capacities. It follows that the market and grid are optimized together. Here, the system operator centrally plans the optimal, congestion-avoiding power plant deployment (“central dispatch”). As long as there are no bottlenecks, the prices at all nodes are at the same level . If congestion occurs, the market prices are adjusted node-wise. That is the market price increases at nodes where increased feed-in or decreased load relieves the congestion and reduces at nodes where decreased feed-in or increased load relieves the congested line. Nodal prices thus represent the “marginal benefit to the system as a whole when an additional MWh is fed in at that node” . The market-based system allows all players to place bids, thus contributing to congestion management .
Grid services in country comparison
In the following, selected countries with their ancillary services processes are described. The explicit selection of countries is based on the research on the alternative concepts already presented, which are already applied there. Figure 1 gives an overview of the considered countries, their mechanisms for redispatching, as well as the provision of frequency control.
Figure 2 shows graphically which of the selected countries apply market-based or regulated and preventive or curative congestion management measures.
The Netherlands – innovative concepts in real operation
Flexibility provision in the Netherlands consists of a combination of passive flexibility provision (“passive balancing”) and cost-optimized intervention by the TSO. There is only one TSO in the Netherlands, TenneT. In order to promote passive balancing in a decentralized manner, the TSO publishes a uniform marginal price for balancing energy in real-time. This serves as a monetary signal for the players and motivates them to adjust their schedules in a grid-serving manner. This form of flexibility is not under the direct control of the TSO. The uniform marginal price reflects the energy price of the most expensive activated reserve unit. In the case of simultaneous activation of positive and negative flexibility to resolve network congestion, a price split automatically occurs, and the incentive for passive flexibility provision, which can be a hindrance to congestion relief by the TSO, is removed. The price split represents an implicit penalty for deviations from the planned production schedule. In addition to passive flexibility provision, actors with an installed capacity of 60 MW or more are required to offer balancing energy in the amount of power that can be produced more or consumed less . Actors with an installed capacity smaller than 60 MW can offer their flexibility on a location-specific basis by bidding as “reserve for other purposes”. Bids can be submitted from seven days before the execution up until the start of the technical preparation period on the execution day, at least about 45 minutes prior. A minimum of 1 MW must be bid for 60 minutes. If necessary, the TSO selects bids for redispatching following the merit order until the congestion is resolved. A capacity and energy charge are paid on a pay-as-bid basis. The process is illustrated in Figure 3.
In the event of congestion, trading on the intraday market (IDM) affecting the congested lines is restricted so that no further congestion occurs. There is no direct activation of control reserve through redispatching, but players with the same capacity can bid for control reserve and redispatching. As a result, when the bid for redispatching is used, players must adjust or withdraw their offer for frequency control .
If the offered balancing energy is insufficient, the TSO calls a request for bids defining the required balancing energy and the affected region. In addition, market participants are then not allowed to deviate from their forecast in the respective direction. If the request is unsuccessful, the request is published again, regardless of location. [15, 16]
France – preventive through sufficiently controllable generation
In France, the procurement of the required flexibility for congestion management is coupled with the required balancing energy for the tertiary reserve of the frequency control within the framework of the “mécanisme d’ajustement” (balancing mechanism). However, planning is done separately: congestion management is planned first, followed by the deployment of the frequency control. Everything is carried out centrally by the sole TSO “Réseau de Transport d’Electricité” (RTE). During congestion management, power plant operators are legally obliged to offer free capacity implicitly . This means that the TSO is informed about the technical schedule as well as the technical capacity of a power plant and is allowed to dispose of the unused capacity of the power plant. The power plant operator sets a price for any schedule change so that remuneration is based on the pay-as-bid principle. To be able to use the most cost-effective reserves with a longer start time, the TSO already activates these reserves preventively up to one hour before they are called up. This is done manually as part of the balancing mechanism. With the actual call of the flexibility, the TSO waits as long as possible so that maximum information about the network state is available.  Since the balancing energy for redispatching is auctioned together with the energy for the tertiary reserve, system operators whose bids are used for redispatching also receive compensation for capacity reservation, regardless of the purpose of activation . In general, in-country line congestion is rarely problematic in France, as much of the generation is not supply-dependent and consequently controllable . The balancing mechanism mainly regulates hydropower and nuclear power plants .
Italy – a mix of zonal and nodal pricing
In Italy, the sole TSO “Trasmissione Elettricità Rete Nazionale” (Terna) acts as the “central dispatcher” and determines the deployment and generation volume of a majority of the plants. The demand for frequency controls, grid congestion management, and the provision of security capacities are jointly optimized in terms of costs. Plants with a nominal capacity of 10 MW or more are legally obliged to submit bids for frequency control or redispatching. They can place them on the market for grid services, the “Mercato del Servizio di Dispacciamento” (MSD). Plants with a lower nominal power cannot qualify for trading on the MSD due to their technical characteristics. Bids on the MSD can also only be placed for grid nodes prequalified to provide grid services. The MSD is divided into two sub-markets: An MSD ex-ante, where bids are used to manage congestion and procure security capacity, and a balancing power market. Remuneration is based on the pay-as-bid principle. A price split is also intended to minimize deviations from production schedules. Regarding time, bids can be submitted on the MSD ex-ante on the day before and on the day of delivery, on the frequency control market only on the day of delivery. The MSD allows trading after the day-ahead market (DAM) and IDM have already settled. Bilateral contracts or long-term procurement of balancing energy do not occur in this market. Trading on the MSD, like the DAM and IDM, is resolved through the Italian power exchange GME. Although the market design for the DAM and IDM is zonal to address structural congestion, bids on the MSD are traded in nodal resolution to act as a corrective for the DAM and IDM, particularly for intra-zonal congestion. The offers are selected by an optimization algorithm taking into account the different applications (redispatching, frequency control, security capacity) as well as the relevant constraints (transmission capacities, technical limits). 
Norway – zonal approach with sufficient hydropower
Scandinavian countries often use a zonal system to counteract grid congestion. This system is used for both in-country and cross-border congestion. Norway has five price zones, Sweden has four, and Denmark has two. The price in each zone is set by the power exchange “NordPool” hourly and is based on planned generation and forecast demand for each zone. In the event of unequal prices between the zones, congestion management costs are recovered through the electricity price. If this is a cross-border line, the revenues are shared equally between the sole Norwegian TSO “Statnett” and the second partner. The total revenue goes to the TSO if it is an intra-country, inter-zonal congestion. 
In Norway, the minute reserve (tertiary control) capacities are used to compensate for forecasted schedule deviations preemptively and resolve congestion. Since the Nordic system is smaller, it requires a minute reserve with a faster ramp-up time in addition to the European standard. Therefore, there are two versions of the minute reserve: one with a ramp-up time of 15 minutes and one with a faster ramp-up time of five minutes. The latter acts as a complement to the secondary reserve. Congestion management uses redispatching and countertrading and resolves inter-zonal and intra-zonal congestion. Reserve capacity is procured jointly with Sweden, Finland, and Denmark in a transnational Nordic reserve capacity market. Players under contract for reserve capacity are required to submit bids to their TSO daily and two days before the call date. The procurement of reserve capacity can take place inside or outside the zone. The decisive factor is that transmission capacity must also be reserved with the reserve capacity before the DAM market closes. The market-based approach recognizes this, i.e., transmission capacity is allocated to frequency control measures if the value of the transmission capacity for reserve capacity is higher than the value of the transmission capacity in the DAM. The reserve options are activated following the merit order. Remuneration is based on the traded reserve product, call duration, feed-in direction, and bidding zone and corresponds to a bidding zone marginal price. If there is no congestion between bidding zones, this price is the same.
An amendment of the current system, e.g., a separation of the procurement of frequency control and grid congestion management, is discussed. 
Great Britain – classic & bilateral
The UK network is not synchronized with the continental European network (UCTE). Trading occurs in a single bidding zone, i.e., congestion is not reflected in monetary terms. In the UK, “National Grid” is the system operator, which is also responsible for grid congestion management and frequency controls. “National Grid” takes a preventive approach and procures capacity for frequency control and redispatching up to one hour before the market closes via various contract models. In addition, bids can be posted and accepted through the “balancing mechanism” (BM), a market for balancing energy. The market closes one hour before the activation time. Most of the capacity used for congestion relief is traded directly and bilaterally before the market closes. Here, the remuneration is also negotiated bilaterally. Smaller quantities used for congestion management or frequency control are traded via the BM after the market closes. Here, there is no differentiation or mutual influence between the two applications, but the use for both applications is cost optimized. The purchased balancing energy is simultaneously used after market close to resolve forecasted congestion and schedule deviations and is activated manually. To minimize costs, the activation of reserves follows the merit order. Bilateral contracts allow the system operator to ramp up power plants before the market closes. The analyses for required frequency controls and redispatching are performed separately. Planning for congestion management starts with a lead time of nine weeks. From 11:00 a.m. on the previous day, power plant operators must transmit their schedule to the system operator and, from then on, inform him permanently of any changes to the schedule. After the market closes, the latter transmits minute-by-minute instructions via the BM, but no further real-time data on system status is published. [16, 23]
In the UK, various contract models exist for the procurement and activation of balancing and reserve energy, of which the most relevant for congestion management are presented below:
- STOR (Short-Term Operating Reserve): STOR represents a reserve for short-term interventions in network operations, such as network congestion management and compensation for production outages. Three times a year, auctions are held for STOR. A minimum of 3 MW or permanent load reduction for at least 120 minutes must be bid. Call-off must be possible three times per week. The player must be prequalified and may not participate in other contract models simultaneously. Remuneration is paid for the reserve and the call. The remuneration for the reserve is determined via the auction. The remuneration of the call-off is determined for BM market participants by bid via the BM, pay-as-bid, and for other players via the auction.
- BM Start UP: Bilateral product that allows the system operator to start up a power plant that would not otherwise produce. This includes power plants that do not participate in trading on the BM. The power plant must be ramped up in 89 minutes from the instruction time. The time of ramp-up and power plant preparation is compensated.
- Transmission Constraint Management: flexible, bilateral congestion management contract for short-term activation as needed. Often, the contract defines a minimum and maximum allowable generated capacity for a power plant. The compensation for provisioning and activation is negotiated bilaterally.
- Maximum Generation: The system operator can dispose of the maximum technical capacity of a power plant and increase production if required. Remuneration is paid for the energy called up. This type of contract involves only current contracts and will be phased out in the future.
For a complete description of the various contract models, please refer to , , and .
Spain – market-based approach according to demand
In Spain, there are four markets for the procurement of balancing energy and operating reserve. The most relevant for congestion management is the “Mercado de solución de restricciones técnicas” (MSRT), the market for solving technical restrictions, which is opened after the market close of the DAM and the IDM and, if required, also at the time of provision. Stakeholders can place bids on the MSRT for a power increase or reduction. For congestion management, most of the balancing energy is traded on the MSRT after the DAM, considering the merit order. After the market close of the DAM, the sole TSO “Red Eléctrica de España” (REE) already tries to counteract grid congestion by reducing accepted ID bids and by publishing site-specific minimum or maximum production limits. Bilateral contracts are not allowed after the DAM market closes. The MSRT is executed directly by the TSO. As shown in Figure 4, it is divided into two phases: In the first phase, congestion is addressed through redispatching, and in the second, the balance between generation and consumption is restored. A cost-optimal selection is made based on the first phase of the MSRT without considering the balancing costs in the second phase. Permanent short-term forecasts of the latest market results and renewable energy consumption and generation are included in the short-term analysis for the grid state after each market closure. All players must inform the TSO of schedule changes or outages, which can be done up to one hour before the execution time. As part of the DAM’s post-market analysis, zonal congestion is identified, and location-dependent maximum and minimum production limits are derived from it, which are taken into account in downstream markets, such as IDM. Theoretically, players affected by redispatching can continue to trade on the IDM as long as this does not create congestion. Congestion that occurs in real-time is resolved simultaneously with any other technical restrictions present at that time. 
USA – the example of PJM – the pioneer of nodal pricing
In the U.S., many regions use a nodal pricing system, whereby grid services are included directly in the price of electricity. System operators are organized as “Independent system operators” (ISO) or “Regional transmission organizations” (RTO). Apart from the RTO “PJM” (Pennsylvania-New Jersey-Maryland Interconnection), the “Southwest Power Pool”, “ERCOT” (Texas), “CAISO” (California), “ISO-NE” (New England), “NYISO” (New York), and the “MISO” (Midwest) also use nodal pricing systems. California switched from a zonal to a nodal system in 2009 because the cost of interzonal congestion was significantly less than intrazonal congestion  and a zonal system does not address intrazonal congestion. Vertically integrated wholesale electricity markets still exist in the Southeast, Northwest, and some states in the Southwest, meaning that system operators often own both generation assets and the transmission and/or distribution system. 
The RTO, as the “central dispatcher,” controls the injection and withdrawal at each node. The nodal DAM solution largely covers congestion relief. After the DAM market closes, the RTO schedules power plant dispatch and reserve capacity in a cost-optimal manner, considering demand, technical production limits, and transmission system capacity. It reports the resulting power plant schedules and nodal prices back to the players. Since this is already a grid-feasible solution, there is no need for redispatching at this point. To continue to operate in a cost-optimal manner, the RTO uses automated evaluation models that simultaneously optimize power plant dispatch and the holding and use of power as frequency control for approximately one hour in advance. The cost-optimal power plant deployment as well as the holding of reserve and frequency control is continuously updated based on market data in real-time from the previous day at 2:15 p.m.. To address deviations from the forecast, the model continuously compares the procurement of energy on the real-time market with the deployment of reserve capacity. When the power plant schedule is intervened, the capacity provided is remunerated according to the nodal price. Even players who deviate from their schedule set the day before must pay the corresponding nodal price, which is calculated automatically every five minutes. If a deviation occurs unexpectedly and at short notice, this is resolved via the frequency control mechanism. Since redispatching and frequency control are based on the same measures, a measure used to resolve congestion is no longer available for frequency control. 
In procurement, the RTO distinguishes reserve capacity and frequency control. Reserve capacity is reserved as standby capacity on the previous day and compensation is paid for the capacity provided. On the day of fulfillment, the need for reserve capacity is checked again and, if necessary, adjusted up to one hour before the time of call. Reserve capacity must be available for at least 30 minutes when activated. Products are traded for 10-minute periods in different categories based on ramp-up time and whether synchronized or not. The capacity for frequency control covers the demand for primary and secondary frequency control and is activated automatically by the control signal in case of a corresponding network condition. Stakeholders can commit to this up to 30 minutes before the call-up time. In this case, no cost optimization is performed, and all participating players must collectively adjust their schedule within five minutes. Remuneration is not based on the nodal price but on performance: The faster the reaction time of the power plant, the higher the remuneration. 
In summary, congestion management measures are currently implemented very individually and depend to a large extent on the available power plant fleet. In the countries considered, mainly large power plants are used to provide ancillary services. Germany seems to play a lone role in the implementation of Redispatch 2.0 and the associated inclusion of small units. Norway, as a country with a high penetration of electromobility (16.9% of the passenger car stock are battery electric vehicles ), can hardly be considered a model for Germany with the predominant provision of electricity from hydropower plants and thus a base-load capable RE resource. Like conventional power plants, zonal pricing works well as a control instrument. The countries considered, which do not operate a zonal or nodal system, exclusively target the deployment of large capacities: For example, in the Netherlands, the minimum bid size is 1 MW, and in the UK it is 3 MW. It can be concluded that Germany is taking a special path, compared to the considered countries, due to the integration of and, in the future, also loads into ancillary services. For the actors involved, this may mean that the provision of ancillary services from small units could initially be a market limited to Germany. However, other countries could also integrate small flexible plants into their ancillary service processes in the future. In this case, players already involved in their implementation today would have an advantage and could contribute their experience from the German market.
In addition to the potential provision of ancillary services by small units, the approach discussed in Germany also includes the advantage of tapping the flexibility potential for grid services in the distribution grid. In addition to establishing energy industry processes and regulations, the prerequisite for this is the connection of the plants via communication and telecontrol systems. Within the framework of the unIT-e² project, approaches for the design of such processes are being developed, and the technical integration of small-scale flexibility – especially from electric vehicles – into the grid and ancillary service processes is being investigated and tested in practice. A German version of this article was also published on the FfE homepage at https://www.ffe.de/veroeffentlichungen/redispatch-international/.
The content described was elaborated in the project “unIT-e² – Living Lab for Integrated E-Mobility”. The activities of FfE Munich in the joint project unIT-e² are funded within the framework of the funding program “Competition Electromobility and Integration into the Energy System from the 29th of June 2020” of the Federal Ministry for Economic Affairs and Climate Action (BMWK) (funding code: 01MV21UN11).
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