Implementing the reformed Electricity Market Design

This paper contextualises the requirements of the Electricity Market Design Regulation and Directive and sets out implementation recommendations from the solar sector for key technical points:

Contracts for Difference (CfDs)

• In general, Member States must design a regulatory framework that ensures a level-playing field for all routes-to-market (on the one hand Power Purchasing Agreements (PPAs), on the other CfDs) and developers should be free to chose their preferred route-to-market.

• Until the hybrid CfD / PPA market is mature, we recommend not overly complicating auctions with non-price criteria in favour of projects selling all of or part of their electricity through PPAs.

• The development of the PPA market on its own must be prioritised, through support schemes to PPA offtakers, and removal of barriers to PPA access.

• It must be possible for assets to be financed by a mix of CfDs and PPAs but we should be careful with the models applied (cf. table on the next slide).

• As a general rule, solar investors should always be able to follow their preferred route-to-market. For example, exiting the CfD should be possible when another business case is made, with clear conditions (penalties, lower strike price for the offtaker, PPA revenues sharing with the gvt..). Re-entering the CfD after the exit should not be possible, with exception, under transparent and strict rules, for a one-time re-entry after PPA termination. 

• We should also always avoid schemes where a public entity reauctions forward products or PPAs to corporates.

• The design of CfDs should not constitute a barrier to investment in flexibility assets, such as storage assets.

• It should be allowed to operate a storage asset freely for hybrid projects under CfDs. The contrary would importantly undermine the full potential of energy storage technology, its ability to dispatch renewable energy at any time of the day, and deploy a fully decarbonised electricity system.

• The obligation to use 2-sided CfDs should not apply to small-scale PV projects : projects under 400 kW, and under 200 kW from 2026 onwards (according to the State Aid guidelines).

• The same assessment should apply to projects designed for self-consumption or any other business model with low or no connection to market sales.

Want to learn more about CfDs? Check out dedicated SolarPower Europe’s CfD guidance

Power Purchasing Agreements (PPAs)

• PPA guarantee schemes are good instruments to improve creditworthiness of PPA offtakers. We highly encourage national governments and public investment banks to set up their own guarantee schemes, at an attractive price.

• PPA guarantee schemes should be designed to  cover all types of consumers presenting potential creditworthiness issues, and de-risk multi-buyer PPAs.

• Creditworthiness is not the only barrier to accelerate the broader PPA market; other barriers exist such as, non exhaustively: buyers' knowledge/education about PPAs, Guarantees of Origin regulatory framework (Access to GO, lack of EU harmonisation) and market interventions (revenue cap during emergency measures).

• Should policy-makers wish to support the growth of the PPA market, other forms of support can also be used, e.g.: promoting existing educational platforms about PPAs and ensuring that the Guarantees of Origins are issued from the start of the project or can easily be issued retroactively.

• Multi-buyer PPAs are a particularly interesting model to grow the access of new consumers to Power Purchase Agreements, particularly consumers with a smaller consumption volume. Such contracts are attractive to the solar industry and to consumers willing to purchase renewable electricity and contribute to the decarbonisation of the energy system. Yet, they remain challenging contracts to close. The involvement of different consumers requires long discussions with different types of consumers, to align on the profile of the PPA, the features to share electricity and the conditions for leaving the contract.

• Public authorities can promote multi-buyer PPAs by improving the knowledge on aggregated PPA models by favouring exchange of good practices, educating the consumer base about multi-buyers PPAs, leveraging Chamber of Commerce or regional economic actors such as regions and cities, and de-risking such contracts.

Energy Sharing

• Member States should use the right to open energy sharing to large companies. Large reliable off-takers can be critical to the success of energy sharing. They can provide larger rooftops for energy sharing and complementary consumption profiles (e.g. consuming shared energy during weekdays when residents are at work or sharing during weekends when residents are at home). Furthermore, their stronger credit profile can be critical for the financial viability of energy-sharing arrangements. 

• Participants in energy sharing must have the right to store electricity either behind the grid connection point of the generator, or at another grid connection point, including behind the meter. This allows the participants to optimise the shared volumes according to varying generation and demand and to mitigate grid congestion. This is closely related to the requirements for Dedicated Measurement Devices in Article 7b) of Regulation (EU) 2019/943. 

• Member States shall incentivise local energy sharing via grid tariffs that reflect the costs of the utilised grid infrastructure.

• The geographical scope for energy sharing may be defined according to   the voltage level of the production units sharing the electricity. We suggest using at least 4 km on medium voltage, 10km on high voltage, and 20 km on very high voltage grids.

Detailed technical recommendations on energy sharing can be found within the paper.

Dedicated Measurement Devices (DMDs)

DMDs should be used for numerous flexibility applications where smart meters don't suffice or where they are not installed already. This allows customers to have dedicated contracts for their devices, such as an EV-charger, or a heat pump, which will increase the adoption rate of dynamic electricity tariffs.

• Where capable smart meters exist, this requires grid operators to accurately account for metering values. They can achieve this by associating a dedicated measurement device with a connection point equipped with a smart meter and by segregating the values accordingly. It must be ensured that the contracted volumes materialise at the connection point to validate the delivery of the service. 

• Certification should be done on a European level through the Terms and Conditions and Methodology developed in the Network code Demand Response. Until such a European certification is found, Member States shall just certify according to existing standards on metering data quality and granularity. Effectively, this amounts to certifying regimes according to IEC 62052-11 (certifies metering equipment in general) and IEC 62053-22 (certifying static meters). 

• Dedicated measurement devices should include all devices which can charge or discharge for example batteries, EV charging infrastructure, heat pumps and inverters). They will complement generation meters, saving customers money and eliminating the time-intensive intervention by the DSO. 

Grid connection procedures & grid hosting maps

• The system operator should provide a digital grid connection system with the possibility to monitor the status of the grid connection à cf. best practices of the Solar Connection report.

• There should be a clear timeline for the grid connection procedure, that the grid operator can reasonably meet, with either a silence means agreement procedure or a penalty if the timeline is not met.

• Having access to more information on grid hosting capacity is very important for the project developer. It will help project developers correctly site projects, but also to appropriately design the projects (for instance choose technologies or choose to collocate projects). This provides a locational signal to developers, i.e. the signal to the developer to locate the projects in the grid where it is most needed. It can also support the speed-up of grid connection processes by externalizing part of the grid connection procedure, as the project developer can make technology choices in the project. At the same time, the data shared on the grid, in the framework of such open data obligations, should be carefully defined in coordination with the system operator. 

• The map information should be updated quarterly, following the flexible grid connections update rule in Article 50 (TSO) and Article 31(DSO). 

• The TSO and DSO map should be presented on a joint platform at the national level. 

• The maps should allow project developers to understand how much capacity is available at key points of the grid. The methodology used to calculate this hosting capacity should also be made transparently available to project developers. 

• Granularity below 1kV is as relevant as above 1kV. For example, in Austria, there are areas/federal states where over 90% of the total connected PV power is based on power plants < 250 kW. 

• The grid maps should improve the dialogue between grid users and operators. A transparent, integrated, and efficient map may minimize misunderstandings and queues of projects. The following list of data has been identified as useful for project developers:

     o The calculation of available grid capacity should be conducted in a technology-specific manner, considering the production profiles of assets seeking connection. It's essential for the available grid capacity to be dynamically updated, considering the possibility of complementary resources in the area, such as wind and solar. Moreover, SOs should openly provide the methodology used for these calculations to ensure transparency and facilitate collaboration within the industry.

     o Possible power capacity transfer (in amperes and MVA) at the substation

     o Grid congestion areas assessment and what is creating the congestion in these areas

     o Grid line sections including the cartography of the line section (overhead and ground) and the location of substations

     o The number of projects in line to be connected by substation – The grid connection requests will have to be digital for TSO and most DSOs. This information could also be translated to the map as done in the USA. In the USA the National grid map is already tracking interconnection queues.

     o The capacity to be reinforced and estimation of time for this by substation. This is already current practice in the Flanders region, Belgium, and Denmark.

Flexible Grid Connection Agreements

• The FCAs will be an important feature of the future energy system. They can be a new tool to speed up the connection of new assets, avoid costly grid connection upgrades for some grid users and incentivise flexible behaviour of the consumer in areas with limited grid capacity. 

• Whereas the Electricity Market Design recommends restricting them to areas with ‘limited or no network capacity availability for new connections’, it should also be possible if requested by the grid user, for grid operators to offer anticipatory flexible connection agreements in areas that will be congested very soon. However, this must be accompanied by strong safeguards to ensure that FCAs do not result in a lack of incentive to reinforce the network or congestion management substitution. Therefore, anticipatory FCAs should be introduced in zones that are not yet congested, provided that (1) the FCAs are static agreements and with compensation to grid users, (2) the grid operator implements a flexibility needs assessment and (3) the grid operator publishes information on volumes and motives for curtailment in their control zones – as provided for in the Electricity Market Design. 

• The regulatory authority should verify that FCA is not used to remedy congestion nor result in a delay in reinforcing the grid – particularly as part of the network development plan. FCA is a mean to make more efficient use of the network capacity but cannot replace current solutions to deal with congestion management.

Detailed technical recommendations on energy sharing can be found within the paper.

Anticipatory Investments

• Must be defined based on the national renewable energy planning, which is realised in close consultation with the industry and aims at identifying the grid reinforcement needs of the industry. This represents a change from the current situation – in several countries, grid operators can include in their network development plans only investments based on actual connection requests. In 2022 SolarPower Europe report showed that network development plans were insufficiently done or insufficiently consulting the industry. 

• Must consider the impact of renewable acceleration areas, but not be strictly tied to it.  RAAs aren’t always considered by developers in different countries.

• Must be based on decarbonisation scenarios in line with 2030 and 2050 climate and renewable energy targets. 

• We must ensure that anticipatory investments and their methodology are fully transparent. 

• Must include CAPEX and OPEX investments. This means for instance costs related to the digitalisation of grid operators or the setup of market platforms. Focus on reinforcing the backbone and not only expansion – also anticipatory investments in the backbone grid should carry less risk than fully new anticipatory investments whereas XB infrastructure inherent risk could be de-risked by cross border infrastructure financers – EIB guarantees? 

• Anticipatory investments should be piloted & urgently translated into national implementation at the TSO and DSO levels. EU funding (DG REFORM) could be used.

• Anticipatory investments should be updated every two years following the update of NDP.

• Anticipatory investments must have a two-level classification of network investments: surely needed and uncertainly needed. To support the uncertain calculation, system operators or regulators should create a system/platform where developers could flag their grid connection needs earlier on, for instance during the planning phase. This could have a financial commitment associated once an actual grid connection is identified, and benefits from fast-tracked permitting. This would be valuable to identify the remote areas relevant for project developers. 

Flexibility Needs Assessments

• There should be two methodologies – one for TSO and one for DSO.

• The flexibility needs should carefully assess the different flexibility needs, including by considering a scenario of a power system functioning fully or almost fully with renewables.

• Developing a comprehensive flexibility framework is paramount. This framework should encompass various flexibility resources and their capabilities, at the TSO and DSO levels. The assessment of the technologies’ capabilities should also include the capability of implicit flexibility resources, in particular self-consumers and collective self-consumers. To this end, an assessment of typical flexible behaviour could be realized. With a comprehensive flexibility framework, System Operators would be able to assess the cost-benefit of grid extension costs vs flexibility procurement.

• Pursuant to the flexibility needs assessment, an action plan with different price signals to activate flexibility should be developed by an authority, and closely monitored by an accountable authority. 

© Shutterstock