Commission Regulation (EU) No 543/2013 of 14 June 2013 on submission and publication of data in electricity markets and amending Annex I to Regulation (EC) No 714/2009 of the European Parliament and of the Council Text with EEA relevance
Modified by
- Regulation (EU) 2019/943 of the European Parliament and of the Councilof 5 June 2019on the internal market for electricity(recast)(Text with EEA relevance), 32019R0943, June 14, 2019
(1) "balancing reserves" mean all resources, if procured ex ante or in real time, or according to legal obligations, which are available to the TSO for balancing purposes;(2) "balancing time unit" means the time period for which the price for balancing reserves is established; (3) "bidding zone" means the largest geographical area within which market participants are able to exchange energy without capacity allocation; (4) "capacity allocation" means the attribution of cross zonal capacity; (5) "consumption unit" means a resource which receives electrical energy for its own use, excluding TSOs and Distribution Systems Operators (DSOs); (6) "control area" means a coherent part of the interconnected system, operated by a single system operator and shall include connected physical loads and/or generation units if any; (7) "coordinated net transmission capacity" means a capacity calculation method based on the principle of assessing and defining ex ante a maximum energy exchange between adjacent bidding zones;(8) "critical network element" means a network element either within a bidding zone or between bidding zones taken into account in the capacity calculation process, limiting the amount of power that can be exchanged; (9) "cross-control area balancing" means a balancing scheme where a TSO can receive bids for activation coming from other TSOs’ areas. It does not include re-dispatching or the delivery of emergency energy; (10) "cross zonal capacity" means the capability of the interconnected system to accommodate energy transfer between bidding zones; (11) "currency" is euro if at least one part of the bidding zone(s) concerned is part of a country in which euro is a legal tender. In any other case it is the local currency; (12) "cut-off time" means the point in time where TSOs have to confirm all matched nominations to the market. The cut-off time refers not only to daily or intra daily markets but also to the different markets that cover imbalance adjustments and reserve allocation; (13) "countertrading" means a cross zonal exchange initiated by system operators between two bidding zones to relieve physical congestion; (14) "data provider" means the entity that is sending the data to the central information transparency platform; (15) "explicit allocation" means the allocation of cross zonal capacity only, without the energy transfer; (16) "flow based parameters" mean the available margins on critical network elements with associated power transfer distribution factors; (17) "generation unit" means a single electricity generator belonging to a production unit; (18) "implicit allocation" means a congestion management method in which energy is obtained at the same time as cross zonal capacity; (19) "market time unit" means the period for which the market price is established or the shortest possible common time period for the two bidding zones, if their market time units are different; (20) "offered capacity" means the cross zonal capacity offered by the transmission capacity allocator to the market; (21) "planned" means an event known ex ante by the primary owner of the data;(22) "power transfer distribution factor" means a representation of the physical flow on a critical network element induced by the variation of the net position of a bidding zone; (23) "primary owner of the data" means the entity which creates the data; (24) "production unit" means a facility for generation of electricity made up of a single generation unit or of an aggregation of generation units; (25) "profile" means a geographical boundary between one bidding zone and several neighbouring bidding zones; (26) "redispatching" means a measure activated by one or several system operators by altering the generation and/or load pattern in order to change physical flows in the transmission system and relieve a physical congestion; (27) "total load", including losses without power used for energy storage, means a load equal to generation and any imports deducting any exports and power used for energy storage; (28) "transmission capacity allocator" means the entity empowered by TSOs to manage the allocation of cross zonal capacities; (29) "vertical load" means the total amount of power flowing out of the transmission network to the distribution networks, to directly connected final customers or to the consuming part of generation; (30) "year-ahead forecast margin" means the difference between the yearly forecast of available generation capacity and the yearly forecast of maximum total load taking into account the forecast of total generation capacity, the forecast of availability of generation and the forecast of reserves contracted for system services; (31) "time" means the local time in Brussels.
(a) details and format of the submission of data laid down in Article 4(1); (b) standardised ways and formats of data communication and exchange between primary owners of data, TSOs, data providers and the ENTSO for Electricity; (c) technical and operational criteria which data providers would need to fulfil when providing data to the central information transparency platform; (d) appropriate classification of production types referred to in Articles 14(1), 15(1) and 16(1).
(a) the total load per market time unit; (b) a day-ahead forecast of the total load per market time unit; (c) a week-ahead forecast of the total load for every day of the following week, which shall for each day include a maximum and a minimum load value; (d) a month-ahead forecast of the total load for every week of the following month, which shall include, for a given week, a maximum and a minimum load value; (e) a year-ahead forecast of the total load for every week of the following year, which shall for a given week include a maximum and a minimum load value.
(a) in point (a) of paragraph 1 shall be published no later than one hour after the operating period; (b) in point (b) of paragraph 1 shall be published no later than two hours before the gate closure of the day-ahead market in the bidding zone and be updated when significant changes occur; (c) in point (c) of paragraph 1 shall be published each Friday no later than two hours before the gate closure of the day-ahead market in the bidding zone and be updated when significant changes occur; (d) in point (d) of paragraph 1 shall be published no later than one week before the delivery month and be updated when significant changes occur; (e) in point (e) of paragraph 1 shall be published no later than the 15th calendar day of the month before the year to which the data relates.
(a) the planned unavailability of 100 MW or more of a consumption unit, including changes of 100 MW or more in the planned unavailability of consumption units, lasting at least one market time unit, specifying: bidding zone, available capacity per market time unit during the event, reason for the unavailability, the estimated start and end date (day, hour) of the change in availability;
(b) changes in actual availability of a consumption unit with a power rating of 100 MW or more, specifying: bidding zone, available capacity per market time unit during the event, reason for the unavailability, the start date and the estimated end date (day, hour) of the change in availability.
(a) the identification of the assets concerned; (b) the location; (c) type of asset; (d) the impact on interconnection capacity per direction between the bidding zones; (e) the estimated date of completion.
(a) the planned unavailability, including changes in the planned unavailability of interconnections and in the transmission grid that reduce cross zonal capacities between bidding zones by 100 MW or more during at least one market time unit, specifying: the identification of the assets concerned, the location, the type of asset, the estimated impact on cross zonal capacity per direction between bidding zones, reasons for the unavailability, the estimated start and end date (day, hour) of the change in availability;
(b) changes in the actual availability of interconnections and in the transmission grid that reduce cross zonal capacities between bidding zones by 100 MW or more during at least one market time unit, specifying: the identification of the assets concerned, the location, the type of asset, the estimated impact on cross zonal capacity per direction between bidding zones, reasons for the unavailability, the start and estimated end date (day, hour) of the change in availability;
(c) changes in the actual availability of off-shore grid infrastructure that reduce wind power feed-in by 100 MW or more during at least one market time unit, specifying: the identification of the assets concerned, the location, the type of asset, the installed wind power generation capacity (MW) connected to the asset, wind power fed in (MW) at the time of the change in the availability, reasons for the unavailability, the start and estimated end date (day, hour) of the change in availability.
(a) the forecasted and offered capacity (MW) per direction between bidding zones in case of coordinated net transmission capacity based capacity allocation; or (b) the relevant flow based parameters in case of flow based capacity allocation.
(a) the main critical network elements limiting the offered capacity; (b) the control area(s) which the critical network elements belong to; (c) the extent to which relieving the critical network elements would increase the offered capacity; (d) all possible measures that could be implemented to increase the offered capacity, together with their estimated costs.
(a) in case of explicit allocations, for every market time unit and per direction between bidding zones: the capacity (MW) requested by the market, capacity (MW) allocated to the market, the price of the capacity (Currency/MW), the auction revenue (in Currency) per border between bidding zones;
(b) for every market time unit and per direction between bidding zones the total capacity nominated; (c) prior to each capacity allocation the total capacity already allocated through previous allocation procedures per market time unit and per direction; (d) for every market time unit the day-ahead prices in each bidding zone (Currency/MWh); (e) in case of implicit allocations, for every market time unit the net positions of each bidding zone (MW) and the congestion income (in Currency) per border between bidding zones; (f) scheduled day-ahead commercial exchanges in aggregated form between bidding zones per direction and market time unit; (g) physical flows between bidding zones per market time unit; (h) cross zonal capacities allocated between bidding zones in Member States and third countries per direction, per allocated product and period.
(a) in points (a) and (e) of paragraph 1 shall be published no later than one hour after each capacity allocation; (b) in point (b) of paragraph 1 shall be published no later than one hour after each round of nomination; (c) in point (c) of paragraph 1 shall be published at the latest when publication of offered capacity figures become due as set out in the Annex; (d) in point (d) of paragraph 1 shall be published no later than one hour after gate closure; (e) in point (f) of paragraph 1 shall be published every day no later than one hour after the last cut-off time and, if applicable, shall be updated no later than two hours after each intra-day nomination process; (f) in point (g) of paragraph 1 shall be published for each market time unit as closely as possible to real time but no later than one hour after the operational period; (g) in point (h) of paragraph 1 shall be published no later than one hour after the allocation.
(a) information relating to redispatching per market time unit, specifying: the action taken (that is to say production increase or decrease, load increase or decrease), the identification, location and type of network elements concerned by the action, the reason for the action, capacity affected by the action taken (MW);
(b) information relating to countertrading per market time unit, specifying: the action taken (that is to say cross-zonal exchange increase or decrease), the bidding zones concerned, the reason for the action, change in cross-zonal exchange (MW);
(c) the costs incurred in a given month from actions referred to in points (a) and (b) and from any other remedial action.
(a) in points (a) and (b) of paragraph 1 shall be published as soon as possible but no later than one hour after the operating period, except for the reasons which shall be published as soon as possible but not later than one day after the operating period; (b) in point (c) of paragraph 1 shall be published no later than one month after the end of the referred month.
(a) the sum of generation capacity (MW) installed for all existing production units equalling to or exceeding 1 MW installed generation capacity, per production type; (b) information about production units (existing and planned) with an installed generation capacity equalling to or exceeding 100 MW. The information shall contain: the unit name, the installed generation capacity (MW), the location, the voltage connection level, the bidding zone, the production type;
(c) an estimate of the total scheduled generation (MW) per bidding zone, per each market time unit of the following day; (d) a forecast of wind and solar power generation (MW) per bidding zone, per each market time unit of the following day.
(a) in point (a) of paragraph 1 shall be published annually no later than one week before the end of the year; (b) in point (b) of paragraph 1 shall be published annually for the three following years no later than one week before the beginning of the first year to which the data relates; (c) in point (c) of paragraph 1 shall be published no later than 18.00 Brussels time, one day before actual delivery takes place; (d) in point (d) of paragraph 1 shall be published no later than 18.00 Brussels time, one day before actual delivery takes place. The information shall be regularly updated and published during intra-day trading with at least one update to be published at 8.00 Brussels time on the day of actual delivery. The information shall be provided for all bidding zones only in Member States with more than 1 % feed-in of wind or solar power generation per year or for bidding zones with more than 5 % feed-in of wind or solar power generation per year.
(a) the planned unavailability of 100 MW or more of a generation unit including changes of 100 MW or more in the planned unavailability of that generation unit, expected to last for at least one market time unit up to three years ahead, specifying: the name of the production unit, the name of the generation unit, location, bidding zone, installed generation capacity (MW), the production type, available capacity during the event, reason for the unavailability, start date and estimated end date (day, hour) of the change in availability;
(b) changes of 100 MW or more in actual availability of a generation unit, expected to last for at least one market time unit, specifying: the name of the production unit, the name of the generation unit, location, bidding zone, installed generation capacity (MW), the production type, available capacity during the event, reason for the unavailability, and start date and estimated end date (day, hour) of the change in availability;
(c) the planned unavailability of a production unit of 200 MW or more including changes of 100 MW or more in the planned unavailability of that production unit, but not published in accordance with subparagraph (a), expected to last for at least one market time unit up to three years ahead, specifying: the name of the production unit, location, bidding zone, installed generation capacity (MW), the production type, available capacity during the event, reason for the unavailability, start date and estimated end date (day, hour) of the change in availability;
(d) changes of 100 MW or more in actual availability of a production unit with an installed generation capacity of 200 MW or more, but not published in accordance with subparagraph (b), expected to last for at least one market time unit, specifying: the name of the production unit, location, bidding zone, installed generation capacity (MW), the production type, available capacity during the event, reason for the unavailability, and start date and estimated end date (day, hour) of the change in availability.
(a) actual generation output (MW) per market time unit and per generation unit of 100 MW or more installed generation capacity; (b) aggregated generation output per market time unit and per production type; (c) actual or estimated wind and solar power generation (MW) in each bidding zone per market time unit; (d) aggregated weekly average filling rate of all water reservoir and hydro storage plants (MWh) per bidding zone including the figure for the same week of the previous year.
(a) in point (a) of paragraph 1 shall be published five days after the operational period; (b) in point (b) of paragraph 1 shall be published no later than one hour after the operational period; (c) in point (c) of paragraph 1 shall be published no later than one hour after the operational period and be updated on the basis of measured values as soon as they become available. The information shall be provided for all bidding zones only in Member States with more than 1 % feed-in of wind or solar power generation per year or for bidding zones with more than 5 % feed-in of wind or solar power generation per year; (d) in point (d) of paragraph 1 shall be published on the third working day following the week to which the information relates. The information shall be provided for all bidding zones only in Member States with more than 10 % feed-in of this type of generation per year or for bidding zones with more than 30 % feed-in of this type of generation per year.
(a) rules on balancing including: processes for the procurement of different types of balancing reserves and of balancing energy, the methodology of remuneration for both the provision of reserves and activated energy for balancing, the methodology for calculating imbalance charges, if applicable, a description on how cross-border balancing between two or more control areas is carried out and the conditions for generators and load to participate;
(b) the amount of balancing reserves under contract (MW) by the TSO, specifying: the source of reserve (generation or load), the type of reserve (e.g. Frequency Containment Reserve, Frequency Restoration Reserve, Replacement Reserve), the time period for which the reserves are contracted (e.g. hour, day, week, month, year, etc.);
(c) prices paid by the TSO per type of procured balancing reserve and per procurement period (Currency/MW/period); (d) accepted aggregated offers per balancing time unit, separately for each type of balancing reserve; (e) the amount of activated balancing energy (MW) per balancing time unit and per type of reserve; (f) prices paid by the TSO for activated balancing energy per balancing time unit and per type of reserve; price information shall be provided separately for up and down regulation; (g) imbalance prices per balancing time unit; (h) total imbalance volume per balancing time unit; (i) monthly financial balance of the control area, specifying: the expenses incurred to the TSO for procuring reserves and activating balancing energy, the net income to the TSO after settling the imbalance accounts with balance responsible parties;
(j) if applicable, information regarding Cross Control Area Balancing per balancing time unit, specifying: the volumes of exchanged bids and offers per procurement time unit, maximum and minimum prices of exchanged bids and offers per procurement time unit, volume of balancing energy activated in the control areas concerned.
(a) in point (b) of paragraph 1 shall be published as soon as possible but no later than two hours before the next procurement process takes place; (b) in point (c) of paragraph 1 shall be published as soon as possible but no later than one hour after the procurement process ends; (c) in point (d) of paragraph 1 shall be published as soon as possible but no later than one hour after the operating period; (d) in point (e) of paragraph 1 shall be published as soon as possible but no later than 30 minutes after the operating period. In case the data are preliminary, the figures shall be updated when the data become available; (e) in point (f) of paragraph 1 shall be published as soon as possible but no later than one hour after the operating period; (f) in point (g) of paragraph 1 shall be published as soon as possible; (g) in point (h) of paragraph 1 shall be published as soon as possible but no later than 30 minutes after the operating period. In case the data are preliminary, the figures shall be updated when the data become available; (h) in point (i) of paragraph 1 shall be published no later than three months after the operational month. In case the settlement is preliminary, the figures shall be updated after the final settlement; (i) in point (j) of paragraph 1 shall be published no later than one hour after the operating period.
| Capacity allocation period | Forecasted cross zonal capacity to be published | Offered capacity to be published |
|---|---|---|
| Yearly | One week before the yearly allocation process but no later than 15 December, for all months of the following year | One week before the yearly allocation process but no later than 15 December |
| Monthly | Two working days before the monthly allocation process for all days of the following month | Two working days before the monthly allocation process |
| Weekly | Each Friday, for all days of the following week | One day before the weekly allocation process |
| Day-ahead | One hour before spot market gate closure, for each market time unit | |
| Intra-day | One hour before the first intra-day allocation and then real-time, for each market time unit |
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