A pragmatic review of battery business cases

As we await the full results of the latest T-4 Capacity Market, which has delivered the lowest clearing price to date for this type of auction, we have been reflecting on the possible business cases for large-scale battery storage. I was speaking on this very topic at the Energy Storage and Connected Systems event in London earlier this week and would like to share our thinking in this area with a wider audience.

We have worked with numerous battery storage developers, investors and traders in the past three years, and while every site has its own design and complexities, the business models can be largely put into three categories: standalone (grid connected); co-located (either with renewables or fuelled generators); and behind the meter for a major consumer.

The standalone option is where we have seen the most activity from a new capacity point of view. This currently tends to be focused on providing services to support the grid through frequency – there is 201MW providing enhanced frequency response (EFR) through the one and only tender of this service in 2016, and a further ~100MW of batteries with firm frequency response (FFR) contracts. The former are four-year contracts which many investors may have considered to be the panacea from a certainty of revenue perspective, sadly for them these contracts are no longer being tendered by National Grid. FFR is available for up to 30 months and therefore offers some price certainty, but this is an increasingly competitive market with an observed fall in prices.

Both these revenue streams can be “stacked” with others to improve the economics and widen the services offered by the batteries. The Capacity Market is one and this potentially offers a 15-year agreement to provide some stability/ certainty to overall revenue streams. Sadly, from an investor point of view, a new one-hour battery in the T-4 will now be de-rated to 36% of its capacity, rather than the previous 96%. This recent regulatory change was on the back of evidence from National Grid that suggested a Capacity Market stress event may last 1.8 hours.  

The other stacked revenue possibility for this business model is embedded benefits. Depending on the connection and frequency contract timings, there may be an opportunity to capture some value from embedded benefits, which I’m sure you’re all aware, have recently been reduced through the Triad review.

Given the increasing competition in the FFR space and sharpening market price signals (both wholesale and imbalance), other strategies are evolving for standalone battery assets. Perhaps for those looking to get debt into their projects, they may consider an arbitrage option as a downside case. This is where the value arises from a combination of wholesale market trading (day-ahead and within-day), the Balancing Mechanism (either directly or indirectly access), potentially another National Grid balancing service (e.g. Fast Reserve) and of course the Capacity Market. Given the introduction of PAR1 imbalance pricing later this year and the increasing penetration of renewables on the system leading to spikier short-term wholesale pricing, this business case may start to look more appetising to developers (but possibly not investors given the lack of price certainty). There are many further complexities to this option, but on a positive note, falling battery costs will make this option more viable generally, and the wholesale market and Balancing Mechanism are significantly deeper markets than frequency response.

Moving onto co-location. This is a complex option but potentially offers greater investor protection as the business model can be more diverse. We have seen some developments of this type in Britain, for instance Anesco’s co-location of solar and batteries. On the one hand, a battery situated alongside solar/ wind may look to shift the load and release the power at more beneficial times of day to maximise the value of the output into the wholesale market. Alternatively, the battery may provide services to National Grid, akin to the standalone option; or, indeed, it may do a combination of the two (in separate windows). In addition, its likely this type of asset will look to achieve further value through the Capacity Market and embedded benefits. This configuration benefits from some shared costs, both connection and O&M.

A major concern for this business model had been fears over losing RO/ FiT accreditation for solar/ wind co-location by making changes to the site. This had centred on addition of storage being deemed to a major change to the site and therefore requiring the solar/ wind project to go through subsidy accreditation again. For the RO, this would mean no more subsidy, as the scheme has now closed to new accreditations. Good news on this front though, as Ofgem has recently published a consultation on guidance for co-locating and maintaining accreditation. One further issue worth considering though is cash-flow under the RO as while Ofgem assesses the changes you make by co-locating storage, your Rocs are suspended, leaving a (hopefully) temporary hole in your revenues.

This is an exciting option, not just for renewables, but there remain some questions over whether it genuinely opens up opportunities for commercially-viable subsidy-free renewables.

Finally, the behind the meter strategy. This is starting to take off in Britain, with low 10s of megawatts being commissioned alongside industrial and commercial sites in the past year. This business case is centred on reducing the electricity costs for major consumers by in effect taking them off the grid (to a degree) over peak times, especially 4pm-7pm on winter weekdays. The costs being avoided include red rates of distribution use of system (DUoS), transmission network use of system (TNUoS i.e. triads) and the Capacity Market supplier charge. All of these costs have increased in recent years and are some are set to continue according to Cornwall Insight’s latest assessments in our Third Party Charges reports.

There is a compelling case for such applications, but they do not come without their drawbacks. The multiple parties (e.g. consumer, battery owner, aggregator) involved can result in contracting complexities and there are some regulatory risks to be aware of, including Ofgem’s Targeted Charging Review, which is focusing on how network use of system charges are levied on consumers and has hinted at looking at behind the meter/ private wire consumers as part of the review.

Cornwall Insight offers a wide range of support to those looking to develop, invest and run battery storage and generation assets. This includes forecasts of frequency response, Capacity Market clearing prices and Third Party Charges (i.e. non commodity costs). We also provide training courses on flexibility and trading and have supported a wide range of flexibility and renewables assets from a regulatory, policy and commercial angle. If you would like to hear more, please get in touch with our associate director, Ben Hall b.hall@cornwall-insight.com.

Related thinking

Energy storage and flexibility

Off-peak electricity use and home generation could cut billions off energy costs

New analysis from Cornwall Insight and Smart Energy GB has revealed the substantial cost-saving potential of household flexible electricity initiatives such as time-of-use tariffs, smart meters, solar PV, and batteries. The has data revealed national wholesale and system electricity costs could be cut by an annual £4.6bn in 2030 and...

Regulation and policy

Capacity Market: Rule changes for upcoming auctions

The latest round of Capacity Market auctions is underway following the publication of the auction parameters on 18 July, with the prequalification window subsequently opening on 26 July. In this blog, we explore some of the changes made to the rules and regulations of the scheme ahead of this year’s...

Energy storage and flexibility

Waiting to connect: the problems and solutions for network connection queues (Part 2)

Network connection queues continue to be a notable topic of interest as many generators face significant delays to project development – an issue that is directly conflicting with net zero ambitions and recent focuses on strengthening domestic energy supplies. In Part 1 of our two-part series on connection queues we...

Energy storage and flexibility

Waiting to connect: the problems and solutions for network connection queues

The number of grid applications has risen significantly in recent years, resulting in increased pressure on the electricity networks to facilitate new connections. In its Energy Security Strategy, the UK government set out ambitions for 95% of electricity to be sourced from low carbon generation by 2030, and for the...

Energy storage and flexibility

Balancing Reserve: ESO proposes new regulating reserve service

In recent months National Grid ESO has been developing a new reserve service to improve the management of the system and enable the grid to accommodate zero carbon operation of the electricity system by 2025. On 28 September the ESO first announced at their Autumn 2022 Markets Forum, a proposal...

Power and gas networks

Gas DSR reforms ahead of winter 2022-23

National Grid has recently carried out a review of the Gas Demand Side Response (DSR) voluntary curtailment mechanism through July and August. The Gas DSR allows shippers to offer a consumption curtailment service to National Grid Gas (NGG) during periods of acute gas supply constraint called a Gas Deficit Emergency...

Energy Market Design

How does REMA impact energy generation, flexibility and consumers?

The Review of Electricity Market Arrangements (REMA) is the largest review programme of GB electricity market arrangements for a generation. It comes at a time when European energy markets are suffering extreme turmoil. Depending on the outcome there could be significant implications for generators, flexibility providers, and, indirectly, consumers. REMA...

Energy Market Design

REMA: electricity market design choices

Electricity markets will serve as the foundation for the future GB energy system.  This article examines some of the market design decisions that will be considered by the Review of Electricity Market Arrangements (REMA). Market design goals At its most simple, a well-functioning market will attract enough potential “buyers” and...