The new electricity market design is intended to better fit the future electricity markets, which will be characterised by more variable and decentralised production, an increased interdependence between cross-border systems and opportunities for consumers to participate in the market through demand response, aggregation, self-generation, smart metering and storage.
It consists of the following acts:
Regulation on the Internal Market for Electricity (recast)
Directive on Common Rules for the Internal Market for Electricity (recast)
Regulation on Risk-preparedness in the Electricity Sector.
Core market principles
The Regulation sets out principles which are to govern the national electricity markets in the future.
Safe and sustainable generation, storage and demand are to participate on an equal footing in the market.
Barriers to cross-border electricity flows and transactions shall be progressively removed.
New network codes shall include rules on demand response, aggregation, energy storage and cyber security.
Day-ahead and intraday markets shall include:
harmonised gate closure times;
short market intervals; and
products with bid sizes of ≤ 500 kW to allow for participation of demand response, energy storage and small-scale renewables.
Transmission system operators (“TSOs”) shall issue long-term transmission rights or introduce equivalent measures to enable hedging of price risks.
There shall be no maximum or minimum limit on wholesale electricity prices, except for harmonised limits on clearing prices for day-ahead and intraday timeframes.
There shall be non-discriminatory access to balancing markets.
Market participants are responsible for the imbalances they cause as a general rule.
Balancing energy is to be settled base on marginal pricing, pay-as-cleared, and within 15 minutes time frames by 2021.
Dispatching of electricity generation and demand response shall be non-discriminatory, transparent and widely market-based.
Priority dispatch for generators of electricity from renewable sources:
mandatory for small renewables and demonstration projects for innovative technologies;
optional for electricity from small high-efficiency cogeneration;
not to be used to justify cross-border curtailment; and
to continue for generators which have already been granted priority dispatch.
Re-dispatching (including curtailment) of generation and demand response shall be open to all kinds of generation technologies, storage, and demand responses, including operators from other Member States.
Non-market-based re-dispatching or curtailment of generators using renewable sources shall be only a measure of last resort.
System operators requesting re-dispatch or curtailment are obliged to financially compensate affected facilities.
Network planning may take into account re-dispatching of up to 5% of the annually generated electricity from renewable energy sources directly connected to the grid.
Congestion should be solved with marked-based methods; transaction curtailment shall only occur where re-dispatching or countertrading is not possible.
Capacity shall be allocated through explicit or implicit auctioning, including both energy and capacity, and be freely tradeable on a secondary basis.
At least 70% of capacity on interconnectors must be available for cross-zonal trade.
Congestion in bidding zones shall be solved by either reviewing the bidding zone configuration or defining action plans including a linear trajectory to reach the benchmark for cross-border trade capacity by the end of 2025.
Capacity mechanisms need to be justified by a resource adequacy assessment.
Capacity mechanisms shall:
be temporary and be phased out as soon as possible;
be open to participation of all resources, including storage and demand-side management;
take the form of a strategic reserve, unless a strategic reserve cannot address the adequacy concerns; and
be open for cross-border participation (if technically feasible).
New power plant must not emit more than 550 gr CO2 per kWh. Grace period until 1 July 2025 for existing power plant emitting more than 350 kg CO2 per kW of installed capacity per year.
Grandfathering rules apply for contracts and commitments entered into before 31 December 2019.
Network access and connection charges shall neither be distance related nor create disincentives for self-generation or self-consumption or participation in demand response.
No positive or negative discrimination against:
production connected at distribution level and production connected at transmission level; and
energy storage and aggregation.
Distribution tariffs must be cost-reflective, taking into account the use of the distribution network by system users.
TSOs and DSOs
Transmission systems operators (“TSOs”) shall co-ordinate with neighbouring TSOs and through regional co-ordination centres (“RCCs”).
RCCs will complement the TSOs’ role by performing tasks of regional relevance, such as the co-ordinated calculation of cross-zonal capacities or co-ordinated security analyses.
Distribution system operators (“DSOs”) may co-operate at Union level through an EU DSO entity.
The EU DSO entity will, amongst other things, play a role regarding the planning of networks and network codes, the integration of renewables, demand-side flexibility and digitalisation.
Customers can enter into aggregation contracts including aggregation for demand response without the supplier’s consent.
Switching suppliers or aggregators shall be possible within three weeks and, by 2026, within one day.
The Directive sets out detailed billing guidelines and information requirements.
Household consumers and micro-enterprises consuming less than 100,000 kWh per annum must have access to at least one independent, free of charge comparison tool covering the whole market and giving equal treatment to the electricity undertakings in search results.
All final customers shall be entitled to (also jointly) act as active customers, i.e. to consume, store or sell self-generated electricity within their premises, or to participate in flexibility and energy efficiency schemes.
can delegate the management of their installations and their balancing responsibilities to third parties;
have the right to network charges accounting separately for the electricity fed into the grid and electricity consumed from the grid; and
have the right to a grid connection.
Citizen energy communities
These are legal entities based on voluntary and open participation of natural persons, local authorities and small or micro-enterprises.
Their purpose is to provide environmental, economic or social community benefits for their members or the local areas where they operate, rather than financial profits.
A citizen energy community can, amongst other things, be engaged in electricity generation, distribution and supply, consumption, aggregation, storage or energy efficiency services, provide charging services for electric vehicles or provide other energy services to its shareholders or members.
Distribution system operators (“DSOs”)
Clarification of DSOs’ tasks, particularly relating to the use of flexibility, co-ordination with transmission system operators (“TSOs”) and development of network development plans.
DSOs may be assigned a role in the integration of electro-mobility into the electricity network and the ownership, development and operation of storage facilities.
DSOs are, in principle, not allowed to develop charging and storage solutions, unless certain conditions are fulfilled.
Transmission system operators (“TSOs”)
The existing provisions for TSOs are largely maintained, with clarifications concerning energy storage, ancillary services and the new regional co-ordination centres.
TSOs are, in principle, not allowed to own, develop, manage or operate storage facilities, nor to own or control assets providing ancillary services, unless certain conditions are fulfilled.
No price regulation
As a general rule, suppliers shall be free to determine the price for the electricity they sell on the market.
Time-limited intervention in electricity price setting for poor and vulnerable customers possible until at least 2025.
For other household consumers and micro-enterprises, Member States may allow regulated prices for a transitional period.
Smart meters and dynamic price contracts
Systematic roll-out of smart meters may be linked to a positive cost-benefit assessment.
All final customers are entitled to receive a smart meter when bearing the associated costs.
Customers with smart meters shall be entitled to enter into dynamic electricity price contracts with at least one supplier.
Suppliers with more than 200,000 final customers must offer dynamic price contracts