For energy storage operators in Great Britain (GB) facing a squeeze in available returns from ancillary services, the Balancing Mechanism (BM) represents a key market for potential revenue. It acts as one of National Grid (NG) ESO’s last means to balance supply and demand on the GB network, before resorting to controlled blackouts. Participants are dispatched by NG’s control room in near-real time, based on both measured and known upcoming imbalances in supply and demand.
The potential opportunity for battery energy storage systems (BESS) in this market is vast, but frustration has grown in recent months as it has become increasingly clear that systems like those managed by Gore Street Capital (GSC) are being ‘skipped’ in favour of larger, higher carbon assets.
These skips occur when the control room utilises an asset even though there is a cheaper alternative available. According to an open letter recently sent to NG ESO by the Electricity Storage Network (ESN), BESS in price-merit order faced an average skip rate of 80% across ten representative units in June 2023 – presenting a £150m annual cost to consumers.
The situation could be even worse according to analysis by Modo Energy, which placed the actual “skip rate” of BESS at 91%.
GSC assets-under-management have experienced this, with the 10 MW Breach Farm asset thought to be one of the most skipped systems when in merit. The 20 MW Lascar system gets triggered in the BM more regularly than the nearby Hulley asset, despite both projects being the same size and in the same region. The lack of transparency over how ESO makes its decisions when selecting assets in the BM is a key barrier to GB’s almost 3 GW BESS fleet delivering cheap, reliable power for consumers.
NG ESO says it generally chooses assets with the most competitively priced bids and offers and sometimes considers other operational and locational factors. Failure to provide further clarity is stopping BESS operators from making informed decisions over their commercial strategy, particularly when such systems offer a cheaper and cleaner alternative to the large-scale gas-peaker plants being selected in their place.
It is possible a wider merit order incorporating system value – voltage support, ability to deliver reactive power with a mandatory service agreement, frequency response, inertia – in addition to economic value is in place, but without knowing the full decision process BESS participants are unable to act accordingly.
The logistics of coordinating a fleet of distributed, decentralised BESS assets could also factor when considering the manual processes governing the BM. Without a digital transformation of the control room, NG ESO can seemingly only deliver a fraction of the volume of actions required for the BM to operate at maximum efficiency. It is instead turning to a smaller number of higher impact actions at the expense of smaller assets that were in merit order—often BESS assets. CCGT plants may offer a simplified solution to the needs of the system, with only one asset called to deal with a multi-settlement-period constraint instead of several, but they are more carbon intensive and this drives indirect further costs for the consumer.
Putting aside questions of whether the BM is functioning as it should, this manual selection process is not effective at a time when the move towards embedded generation and lower capacity plants has been underway for over a decade.
A Bulk Dispatch Optimiser (BDO) tool is scheduled for introduction in December 2023 that could deliver up to 300 instructions multiple times per hour, but NG ESO’s IT strategy is already delayed and, according to Ofgem, well over budget.
These issues go far beyond the ESO, however. It's fair to ask why Ofgem's oversight hasn't required NG ESO to deliver a better system that was clearly required years ago. If delivered on schedule, the BDO is due to be available almost five years after batteries started operating in the BM. It was already a well-established fact back then in January 2019 that generation was moving towards smaller-scale, embedded generation and so improvements to the BM’s operational processes should already have been prepared and implemented.
As the manager of London’s first internationally diversified energy storage fund, GSC has experience operating BESS in markets without a BM. Assets in Germany derive liquidity from the demand for generators to settle their supply imbalances before facing high system charges, removing the need for a BM equivalent.
In Texas, meanwhile, grid constraints are settled every five minutes based on the most economical bids able to solve local issues. Supply and demand are continually optimised to tackle low grid resiliency, although huge price spikes can occur when the risk of under supply is high at a time of considerable demand such as during extreme weather events.
Where these markets offer lessons to GB is in the heightened transparency available to operators over how decisions are made in the control room, rather than just the outcomes of those decisions. The German and Texas grid markets provide clear methodologies for the choices being made and, as a member of the ESN, GSC supports its calls for clarity over GB BESS dispatch versus other technologies and greater urgency in effective dispatch. This will benefit the grid, add to the longevity and sustainability of future energy balancing and, ultimately, reduce costs for consumers.