REMA (Review of Electricity Market Arrangements) is set to introduce the biggest changes to electricity markets in Great Britain since the introduction of the Capacity Market and Contracts for Difference (CfDs).
But why are these huge changes being considered? Here’s what BEIS has said:
“We do not consider that existing market arrangements are likely to deliver our ambition for a decarbonised and secure electricity system by 2035 at least possible cost to consumers.”
The consultation on REMA is closing soon (10 October 2022). In this article, we provide a high-level, storage-focused summary of three key themes from the review:
- Locational markets.
- Split power markets.
- Government intervention.
1) Locational markets
Currently, the main tool for managing locational issues (e.g. network constraints) is the Balancing Mechanism. REMA notes (page 32):
“As renewable generation investment has outpaced network reinforcement, constraint costs have increased significantly in recent years, from around £360m in 2015 to £1.2bn in 2021.”
One of the options being considered in REMA is a move to locational markets. By matching generation and demand at local levels, investment and development will be incentivized in areas that need it most. (Robyn, our Chief Analytics Officer, recently wrote a series on Nodal Pricing - so check it out!)
How would this affect battery energy storage?
Locational markets would support the business cases of assets able to manage constraints more effectively, based on location.
In the current market, network constraints are addressed through longer-term, broad network charges and real-time Balancing Mechanism actions. (Be sure to check out Imrith’s recent piece outlining the reasons why Balancing Mechanism actions are taken.)
A locational market would help to target constraints more accurately. Wholesale prices would provide clear market signals to identify constrained regions. This would drive appropriate investment in flexibility assets. On top of this, the shape of the pricing would signal exactly which types of assets - interconnection, storage, curtailment, etc. - are needed.
For an example of what supply and demand might look like in different locations, figure 1 (below) shows the modeled make-up of embedded generation in each of the GSPs by winter 2025/26, according to the Leading the Way scenario (from FES 2021). We have overlaid projected average demand (the purple line).
Any potential downsides?
The integration of the systems needed to connect and balance locational pricing will be complicated and operationally challenging. A combination of the huge changes needed and regulatory uncertainty may dent investor confidence in the short term.
If a location is constrained and therefore generating high price spreads, this is a good incentive for storage to be built - great! Once in place, the constraint can be addressed - again, great! So what’s the problem? Well, once the constraint is addressed, the question of market depth arises. Would market design allow for enough price shape (post-build) for the storage to deliver on its business case? These are questions REMA will need to answer.
2) Split power markets
Storage is a provider of flexibility. The business case relies on charging at low prices (e.g. reducing generation oversupply) and discharging at high prices (e.g. replacing carbon-intensive peaking assets).
“As available” vs. “on-demand”
A split market suggests that one power price is created for “as available”, intermittent generation - set by the long-run marginal cost(s) of renewables. In theory, this would be at a similar price level to contracts for difference (CfDs). Another power price is created for “on-demand” power - set by the short-run marginal cost(s) of flexible plant.
- How does “on-demand” storage work in this instance? If the lowest price is in the “as available” market, consumers will want this price over the higher “on-demand” rate.
- Will storage assets then join a queue of consumers for the cheaper “as available” power?
- If there is a clear spread between the two, and demand for both, will storage repeatedly cross that gap? And cycle multiple times per day in the process?
- More importantly, will those price signals encourage the necessary behavior to balance the wider energy market?
Can REMA find an alternative solution?
A key benefit of this market is thought to be the decoupling of (a portion of) renewable generation from gas prices. But could this be more easily achieved by expanding the CfD scheme to include all intermittent generation? The resulting costs/benefits could then be distributed across consumers.
It’s also possible that pricing set by long-run marginal costs would dilute the flexibility of intermittent assets - by discouraging assets from turning down at times of negative pricing.
3) Government intervention
When we talk about ‘storage’ at Modo, we’re generally referring to the short-duration (30-120 minute) battery energy storage deployed today. It’s a locational tool that can be rapidly deployed for distributed and transmission-level balancing actions. The broader storage category - including medium- to long-duration storage and future pumped hydro - is less flexible. However, the longer durations and higher throughputs make it more suitable for a wider variety of services (e.g. inter-week balancing services or constraint management).
Why does this matter?
Storage isn’t the only tool that can manage constraints or help balance increasing renewable penetration. The challenge for government will be selecting the appropriate market structure(s) and support mechanisms to best make use of our low-carbon flexibility portfolio.
Imagine a transmission cable is constrained for four hours, once per month. Should the market encourage the building of another transmission line? Or storage? Maybe it should simply allow the constraint? Or implement another solution altogether? There are numerous alternatives to storage that could be deployed, including:
- Interconnection (cap and floor) / network reinforcements.
- Hydrogen (albeit largely adjacent to power markets, as outlined in Michael Leibreich’s hydrogen ladder).
- CCUS (if/when operationally proven).
- Constraint costs and/or curtailment.
- Demand side response.
When any or all of these solutions are implemented, what sort of impacts will they have on storage? Following the REMA consultation, government needs a balanced approach - and fair markets - to enable these technologies to coexist, compete, and deliver a low-cost transition.
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