The government continues to play catch-up in terms of driving storage provision. This has lagged far behind renewable generation projects already completed and those awaiting approval. There’s been a historic shortage of UK-based large-scale battery manufacturing. Storage demand can only grow with, for instance, the offshore wind sector hoping to see the largest capacity allocation – over 8 GW is expected – under the latest Contracts for Difference (CfD) process. Successful bidders are due to be announced either this December or in January 2026.

Currently, an estimated 6 GW of battery energy storage system (BESS) capacity is operational in the UK. NESO, the UK’s nationalised energy system operator overseeing electricity transmission and plans for renewable energy deployment, intends to prioritise ‘ready-to-build' projects for connection offers. The idea is to remove the logjam holding up many schemes that have been granted planning consent.

NESO modelling claims that the UK will need at least 23 GW of battery storage by 2030 to decarbonise the grid. Industry sector group Battery Storage Coalition has long grumbled about this technology not being prioritised in the energy system ‘despite receiving no subsidies’. It complains of outdated regulations, market rules and ‘old NESO practices threatening investment and deployment’. Coalition members have over 70 battery storage sites either built or in planning across the UK, with 3.4 GW of operational capacity – more than half the UK total.

Not only is the number of BESS schemes growing, so is their size. A decade ago, the average application submitted for planning was 2 MW. In July 2025, among those approved was Lightrock Power’s 600 MW Stable Green Energy project. However, battery storage is most commonly thought of as only offering short-term storage, of the order of a few hours.

The government hopes new investors to technologies such as pumped hydro storage and compressed air storage will be drawn in by a proposed ‘cap and floor’ scheme, intended to provide a minimum revenue guarantee. The scheme would allow a ‘fair return’ covering investment costs, providing a measure of financial stability, especially for debt financing. Meanwhile ‘excessive profits’ would be capped. This initiative is set against a backdrop of BESS companies and investors having struggled because market arrangements worked against them making a worthwhile profit.

Ofgem’s scheme will last 25 years and be funded through network charges on energy suppliers. Eligible projects must provide long-duration storage services (LDES) – a minimum of eight hours – and satisfy technical and financial viability criteria, for example, a capacity of 100 MW or 50 MW depending on the technology.

Commercial development of LDES needs financial support because of high upfront capital costs and uncertain revenue streams. Schemes also face long lead times for planning approvals and construction – facilities can take several years to build. A cost benefit analysis (CBA) of applications made in the two-month window, which closed in June, is underway. All will undergo Ofgem’s ‘collective assessment… to maximise whole-system benefits’. Effectively, projects will be competing against each other.

The CBA process is expected to be completed in spring 2026, with cap and floor award decisions finalised. Then construction will begin. From 2029–2031 there’ll be a post-construction review. Ofgem anticipates that the outcome will produce between 2.7 GW and 7.7 GW of extra storage capacity by 2035.

Why is this necessary?
Often the government’s net zero ambitions have stuttered in the absence of a joined-up approach. There are, for instance, surprisingly few co-located projects – where renewable generation and battery storage are combined at the same grid connection point. This would appear to be an efficient and cost-effective way forward, yet too often such schemes have been blown back by the headwinds of market, grid and planning complexities, as well as technical challenges.

In theory, a boost to energy storage should work wonders in helping manage the fluctuations such as those generated by renewable sources like wind – especially in Scotland, where so much power can be wasted. But there’s little chance of this happening quickly. Developers of low-carbon energy infrastructure are plagued by long lead times for connection to electricity transmission or distribution networks.

That said, Mark Macaulay, Glasgow-based partner with Global law firm Dentons, who’s been advising the industry since the cap and floor concept began to emerge two years ago, considers Ofgem’s initiative a significant step towards the government achieving its aim – balancing investor incentives with consumer protection.

‘Historically, developers have struggled to attract financing through being unable to predict revenue flows from energy arbitrage (buying cheap power then storing it for later use when prices are high) and in longer-term capacity markets,’ he says.

‘Cap and floor provides some certainty over a 25-year period that should encourage investment. But further clarity is needed. In June 2025, Ofgem launched a consultation offering more detailed proposals, including a draft model and a handbook to explain how cap and floor levels are calculated. Yet the final approach to how rates will be determined is still pending. Given the financial model is central to viability, delays could hinder early development,’ he remarks.

A balance will need to be struck between convincing investors without hiking household bills. ‘While protecting consumers from excessive costs is a legitimate concern, [Ofgem] does not sufficiently address long-term affordability,’ says Macaulay. ‘And what happens beyond the 25-year support window? Will these projects continue to benefit from floor prices if they remain essential for grid stability?’ he inquires.

Macaulay calls on Ofgem to provide greater clarity on financial parameters, cost eligibility and post-regime arrangement: ‘Without this, there’s a risk that developers will remain hesitant,’ he warns.

There is, he adds, another major obstacle to progress. ‘Ofgem doesn’t offer a concrete solution to ease the long interconnection delays plaguing renewable and storage projects. These are now the bottleneck. It’s acknowledged the issue without yet setting out a full solution. It could standardise queue reform nationwide and enforce strict deadlines.’

What’s the state of the connections queue?  
It’s pretty clear to everyone in the industry that a major rebalancing needs to take place. NESO says that the connections queue has grown 10-fold in just five years and currently stands at 738 GW, more than four times the clean generation capacity required by 2030. As recently as January 2025, there were more than 9,000 projects, many of them speculative or non-viable and destined never to go ahead.

Ofgem and the Department for Energy Security and Net Zero (DESNZ) have been attempting to address this issue for some time. In November 2023, Ofgem announced a policy to clear ‘zombie projects’ and cut waiting time for grid connections. It ended the ‘first come, first served’ system and allowed stalled or speculative projects to be jettisoned from the connections queue. In fact, the weeding-out process began in 2022 via a Transmission Energy Capacity (TEC) ‘amnesty’, allowing customers to leave the queue or reduce TEC with no or little cost.

NESO’s five-point plan to improve the grid connection process at transmission level was approved by Ofgem in April 2025, which in January accepted a six-month pause on accepting new connection applications. Two years earlier, the Energy Network Association (ENA) – responsible for ensuring connections comply with technical and legal requirements – set out its own ideas to simplify things at distribution level.

Among ENA’s suggestions were releasing up to 90 GW of capacity by ‘cleaning up’ the queue. Instead of first come, first served, it began managing a ‘first ready, first connected’ process. It also proposed accelerating up to 70 GW of applications by allowing some to connect faster, before network reinforcements are completed.

How has that gone to date? ENA says that since 2023, networks have delivered ‘substantial progress’. There has, it declares, been ‘robust’ queue management at both transmission and distribution levels, with over 11 GW of zombie projects removed from the queue.

So far, ENA claims to have offered accelerated distribution connections dates to over 14 GW of projects. David Boyer, ENA’s Director of Electricity Systems, says: ‘Typically, these are offered where continuous power supply isn’t required. This work has sped up connection time by an average of six and a half years.’

He continues: ‘There’s a real sense of urgency to connect new schemes of all types to the grid. The existing process needed to change in part because viable projects were being stuck behind non-viable ones, while the queue grew at a rate which far exceeds the nation’s requirements. This is what’s driven a delay in connecting customers – and why we’re working with government and the wider industry to implement reforms. One element is changing the modelling and assumptions for storage projects at both transmission and distribution level to better align with actual usage patterns – 65 GW of capacity has been released through this. These alone won’t remove current obstacles. We also need to continue modernising planning processes and the approach to land rights to ensure local decisions align with national priorities. That will help networks deliver government ambitions for renewable infrastructure investment.’

The rate of progress will depend on swift and efficient decision-making; and there’s a lot of ground to make up. Macaulay isn’t expecting miracles. ‘ENA’s track-record has suffered from a lack of prioritisation,’ he says. ‘You can’t just go from zero to 100 miles an hour overnight.’

• Further reading: ‘World’s largest sand battery enters operation in Finland’. Loviisan Lämpö has commissioned the world’s largest sand battery, a high-temperature thermal energy storage system. Developed by Polar Night Energy, the industrial-scale sand battery now serves as the main production facility for the district heating network in Pornainen, Finland.
• Find out why pumped hydro is back in vogue for energy storage.