|Central Dispatch Model|
According to Article 2(18) of the Commission Regulation (EU) 2017/2195 of 23 November 2017 establishing a guideline on electricity balancing, ‘central dispatching model’ is a scheduling and dispatching model where the generation schedules and consumption schedules as well as dispatching of power generating facilities and demand facilities, in reference to dispatchable facilities, are determined by a Transmission System Operator (TSO) within the integrated scheduling process.
The central dispatch model represents one of the two types of dispatching arrangements currently in parallel existence in the European electricity markets (the other being the self-dispatch system).
ACER's Recommendation No 03/2015 of 20 July 2015 on the Network Code on Electricity Balancing observes the dispatching model is essentially an approach to how the generation schedules and consumption schedules for dispatchable power generating facilities or demand facilities are determined.
Central dispatch models typically occur in electrical systems where the impact of locational market imbalances is a material threat to the security of the system. In such systems, a central dispatch model can be considered a necessity.
In some countries (e.g. Greece, Hungary, Ireland, Italy, Northern Ireland and Poland) there is a need for central dispatch in order to ensure system security and minimise the cost of energy delivery to the end consumer.
Pursuant to the Supporting Document for the Network Code on Electricity Balancing of 6 August 2014 it is not expected that the number of TSOs operating central dispatch systems will increase or decrease in the near future.
The above Supporting Document describes the central dispatch as a dispatch arrangement where the TSO determines the dispatch values and issues instructions directly to resources.
The TSO determines the dispatch instructions based on prices and technical parameters (including the start-up characteristics) provided by the resources, as well as whole network model.
The TSO constructs a schedule for the day based on commercial and complex technical data from the resources, taking into account all the security constraints of the whole grid model.
The typical objective for the dispatching process (or unit commitment process) is the minimisation of energy delivery cost to meet system demand as forecasted by the TSO while complying with operational security requirements.
The main distinguishing feature of central dispatch systems is that balancing, congestion management and reserve procurement are performed simultaneously in an integrated process.
Integrated scheduling process is defined in Article 2(19) of the Commission Regulation (EU) 2017/2195 of 23 November 2017 establishing a guideline on electricity balancing as “an iterative process that uses at least integrated scheduling process bids that contain commercial data, complex technical data of individual power generating facilities or demand facilities and explicitly includes the start-up characteristics, the latest control area adequacy analysis and the operational security limits as an input to the process”.
This can involve dispatch instructions being issued many hours ahead of real-time, to start up units, to real-time instructions for dispatching on-line units.
The above differentiation seems important to understand balancing rules as drafted in the ENTSO-E Network Code on Electricity Balancing, which is predominantly designed from a self dispatch model point of view and the central dispatch model requirements are met through special provisions.
The special provisions for central dispatch systems included in the said draft Network Code are as follows:
- allowance for TSO to convert/refine Balancing Service Providers’ (BSP's) bids before submission to activation/procurement optimisation function,
- allowance for TSO to set special rules for submitting, activation and updating bids by BSPs,
- all rules have to be fair, transparent, non-discriminating and National Regulatory Authority approved.
TSOs operating central dispatch systems will have the right to include the following within the terms and conditions related to balancing:
a) limit the submission, and updating of integrated scheduling process bids by defining integrated scheduling process gate closure times in order to ensure that firm integrated scheduling process bids are available as an input to the integrated scheduling process; and
b) activate integrated scheduling process bids prior to the balancing energy gate closure time on the basis of the results of integrated scheduling process.
Due to the nature of the dispatch arrangements, the NC EB gives TSOs of central dispatch systems the option to propose amendments to the rules for updating balancing energy bids such as requiring bids before start of local integrated dispatch process and limiting the possibilities to change submitted bids due to on-going dispatch process.
TSOs of central dispatch systems can convert bids submitted by BSPs before submitting them into common procurement or activation.
This allows TSOs to reflect in cross-border balancing bids submitted by the TSOs their previous actions; current system state; technical availability of bids; and real cost of their activation.
Requirements for conversion of bids in a central dispatching model are stipulated in Article 27 of the Commission Regulation (EU) 2017/2195 of 23 November 2017 establishing a guideline on electricity balancing - see box.
Another central dispatch specificity is involved with the rule that generally the terms and conditions related to balancing must:
(a) allow the aggregation of Demand Side Response, the aggregation of generation units, or the aggregation of Demand Side Response and generation units within a Responsibility Area or Scheduling Area where appropriate to offer balancing services;
(b) allow Demand Facility, aggregators and generation units from conventional and renewable energy sources as well as storage elements to become Balancing Service Providers; and
However, the TSOs operating central dispatch systems will not be obliged to allow within the terms and conditions related to balancing the aggregation of Demand Side Response, the aggregation of generation units, or the aggregation of Demand Side Response and generation units pursuant to the above principle.
There are no special arrangements for central dispatch systems in imbalance settlement.
Modification of bids in central dispatch systems
TSOs operating central dispatch systems will have the right to use integrated scheduling process bids for the purpose of the Exchange of Balancing Services.
TSOs operating central dispatch systems will be under the obligation to use all integrated scheduling process bids respecting operational security constraints, to provide balancing services to other TSOs.
TSOs operating central dispatch systems will have the right to modify integrated scheduling process bids referred above for the purpose of the Exchange of Balancing Services taking into account operational security.
Integrated scheduling process bids modified by TSOs operating central dispatch systems for the purpose of the Exchange of Balancing Services must be compatible with standard products exchanged in Coordinated Balancing Area (CoBA).
The example of the said processes is the bid conversion for the purposes of the European platform for the exchange of balancing energy from replacement reserves (RR Platform).
Pursuant to the proposal of all Transmission System Operators performing the reserve replacement for the implementation framework for the exchange of balancing energy from Replacement Reserves in accordance with Article 19 of Commission Regulation (EU) 2017/2195 of 23 November 2017 establishing a guideline on electricity balancing (ENTSO-E, 21 February 2018) TSOs applying a central dispatching model will convert integrated scheduling process bids received from the BSPs into replacement reserve (RR) standard products and then submit the RR standard product to the RR Platform.
Integrated Scheduling Process Gate Closure Time
Each TSO operating a central dispatch system should define an integrated scheduling process gate closure time for its Responsibility Area.
Integrated scheduling process gate closure time is defined in Article 2(20) of the Commission Regulation (EU) 2017/2195 of 23 November 2017 establishing a guideline on electricity balancing as “the point in time when the submission or the update of integrated scheduling process bids is no longer permitted for the given iterations of the integrated scheduling process.”
According to Article 18(8) of the said Commission Regulation (EU) 2017/2195 of 23 November 2017, TSOs applying a central dispatching model are required to include the following elements in the terms and conditions related to balancing:
(a) the integrated scheduling process gate closure time;
(b) the rules for updating the integrated scheduling process bids after each integrated scheduling process gate closure time;
(c) the rules for using integrated scheduling process bids prior to the Balancing Energy Gate Closure Time;
(d) the rules for converting integrated scheduling process bids.
An integrated scheduling process gate closure time should:
(a) not be after balancing energy gate closure time;
(b) be allowed to be before the intraday cross zonal gate closure time;
(c) ensure sufficient time for TSOs to perform integrated scheduling process; and
(d) ensure sufficient time for TSOs to prepare and submit balancing energy bids to the activation optimisation function.
After the integrated scheduling process gate closure time the volume and price of the integrated scheduling process bids can only be changed with approval of the Connecting TSO.
Controversies regarding the role of Central Dispatch Systems in the EU Internal Electricity Market
The parallel existence in the Network Code on Electricity Balancing of self-dispatch systems and central dispatch systems sparked some criticism.
Eurelectric claims in the ENTSO-E Network Code on Electricity Balancing, a EURELECTRIC comments paper (August 2013, p. 5) that "it is difficult to imagine a functioning balancing market integration of Central Dispatch systems in the European internal electricity market" and asserts that "ENTSO-E have not provided sufficient justification as to how the articles relating to central dispatch ensure a level playing field with regard to balancing between self and central dispatch systems".
According to the Eurelectric central dispatch systems should be regarded as derogations only, and not as an "alternative target model" in the European Union Internal Electricty Market. Eurelectric also postulates these systems should be limited to countries which already operate as central dispatch systems at the date of the entry into force of Network Code on Electricity Balancing.
There were also views from another end of the spectrum, not agreeing with the Eurelectric stance, and especially with those regarding treatment as derogations.
The argument has been raised, the Eurelectric approach would prejudice the right to establish national network codes as provided for in Article 8(7) of Regulation 714/2009.
It would, moreover, in effect require a change to a self-dispatch market and contravene the Framework Guidelines on Balancing which states:
"... the European Network of Transmission System Operators for Electricity (ENTSO-E) shall take into account the parallel existence of central dispatch and self-dispatch arrangements of European electricity markets when drafting the Network Code on Electricity Balancing in line with these Framework Guidelines."
The latter conception has prevailed in the final draft for the Electricity Balancing Network Code prepared by the ENTSO-E, but ACER in the Recommendation No 03/2015 of 20 July 2015 on the Network Code on Electricity Balancing, surprisingly (since this stance seems to be departing from ACER's Framework Guidelines) called for stricter application of the central dispatch model.
The amendments proposed by the ACER aimed to clarify that the self-dispatching model is the primary dispatching model to be applied by TSOs for determining generation and consumption schedules, whereas the TSOs applying a central-dispatching model at the time of entry into force of the Electricity Balancing Network Code may request an appropriate exemption from the competent regulatory authorities to be allowed to continue.
The main reason of this stance was that, in the ACER's opinion, the self-dispatching model is more in line with the European target model with a zonal congestion management.
Finally, Article 14(2) of the Commission Regulation (EU) 2017/2195 of 23 November 2017 establishing a guideline on electricity balancing mandates each TSO to apply a self-dispatching model for determining generation schedules and consumption schedules, while TSOs that apply central dispatching model at the time of the entry into force of the said Regulation are required to notify to the relevant regulatory authority in order to continue using it.
The relevant regulatory authority is required to verify whether the tasks and responsibilities of such TSO are consistent with the definition of the central dispatching model as stipulated in Article 2(18) of the said Regulation.
Electricity Balancing Network Code (Commission Regulation (EU) 2017/2195 of 23 November 2017 establishing a guideline on electricity balancing), Article 2(18)
|Last Updated on Monday, 12 March 2018 20:03|