The CRU is consulting until 14 April 2025 on the Sharing of Maximum Export Capacity (“MEC”) behind a Single Connection Point.

This is the second of the three workstreams to remove barriers to hybrid connections, intended to enable multiple electricity and/or storage technologies to co-locate behind a point of connection to the grid. The workstreams are:

• removal of the Installed Capacity Cap of 120% of MEC for single and hybrid technology sites, addressed in the Installed Capacity Cap Decision,
• sharing MEC behind a single connection, the subject of the current proposal, and
• allowing multiple legal entities to share a single connection point. This is not yet addressed, although the current consultation invites feedback as to measures that may be required and whether they can be addressed in ongoing workstreams (see question 9).

Sharing MEC

The aim is to maximise the use of existing grid infrastructure by allowing different technology types behind a single connection point to dynamically share a single MEC. Currently, hybrid co-located projects are registered as separate units in the Single Electricity Market (“SEM”). Projects seeking to install further technologies must apply to the System Operator (“SOs”) for increased MEC, or split the MEC between units.

Under the proposal, where an existing project wishes to add another technology behind their connection, they would still be required to apply for approval through the Modifications to Generation Connection Offers process. However, the need to apply for increased MEC or to sub-divide the MEC between unit types would be removed.

Notably, the proposal is not intended to allow generation that has been constrained or curtailed down to be used to charge co-located storage.

Priority Dispatch

The CRU’s view is that, if renewable generators with priority dispatch seek to convert a site to a co-located hybrid project and/or avail of the sharing of MEC, this is likely to be classified as a ‘significant modification’, for the purposes of the IME Regulation, and liable to lead to loss of priority dispatch status.

Given the importance of priority dispatch to certain sites, such a statement by the CRU will deter many projects from seeking a hybrid connection. It would be helpful to consider whether this is a view that is necessary to reach. It does not appear to be required from a legal viewpoint, in that the threshold in the IME Regulation as to whether a power-generating facility has become subject to a significant modification is that it is deemed to be the case “at least where a new connection agreement is required or where the generation capacity of the power-generating facility is increased”. Neither is it clear that the CRU’s view is based on the SEM Committee’s interpretation in SEM-20-072. The SEMC considered that a ‘power generating facility’ should be interpreted to mean a Generator Unit as defined in the Trading and Settlement Code (whereas the current proposal is concerned with adding separate units, additional to the unit behind a connection). The SEMC also considered that extension to a facility where there is a separate unit with its own control system and MEC, acting as a separate unit in the Market, would not be considered a significant modification, and that the existing Generation Unit would retain priority dispatch.

Operational and Legal Arrangements

The CRU proposes that each unit type continues to be registered separately in the SEM, and all would either register under a single Trading Site, or each would register under separate Trading Sites. These alternatives are to be explored in an Implementation Roadmap by the SOs. How the MEC would be shared would be a matter for the party managing interactions with the SEM. Each technology would have sub-meters.

The SOs indicate that they need to review:

• bonds required for Connection Charges and Capacity Charges;
• provisions in Connection Agreements;
• modelling estimated total dispatch down for network planning studies;
• market systems and registration under the Trading and Settlement Code;
• participation in the Capacity Market and appropriate de-rating factors;
• provision of System Services;
• tariffs, levies and charges (including TUoS and the PSO). For example, it is suggested an additional aggregate charge may apply to GTUoS;
• the distribution system flexibility market; and
• SO business processes, including in relation to site controllability, metering, site controllability set points, availability declarations, forecasting, central dispatch arrangements options, Grid and Distribution Code compliance, and the application of Network Codes.

Further details are in the annexes to the proposal. For example, the SOs suggest that customers would install internal control systems so that site output does not exceed contractual and operational limits. It is suggested that declared Availability for each unit should be such that total availabilities do not exceed MEC. It is noted that this may have knock-on impacts on market positions possible for each unit, and that policy may need to ensure that real-time availability signals reflect the actual status of each technology.

Stakeholders will wish to comment on these details and potentially bring further suggestions to the table. Industry stakeholders should bear in mind the importance of robust interface arrangements between units (and entities, once that is provided for) at co-located sites, to manage individual and shared risk around compliance with the relevant market and grid arrangements.