The last year provided the UK with an extended sneak preview of the energy system of the future.
The downside though was that periodic excesses of renewable energy meant wind farms having to be switched off at particularly gusty times, fuelling a £718 million payout of balancing costs to generators by the Electricity System Operator (ESO) in the second quarter of 2020.
The size of this payment illustrates how dramatically increased capacity to store electricity will be required to help the grid match the greater peaks and troughs in demand and supply that look set to be a feature of an increasingly intermittent energy system.
“Our system is getting more stressed at times of low demand which is when renewables need to be curtailed. Storage is valuable because it allows that otherwise curtailed demand overnight to be used,” says Bob Hull of consultancy Riverswan Energy Advisory, and previously a senior figure at both Ofgem and National Grid.
By 2050, the ESO has calculated that the UK will require 40GW of additional storage capacity, 15GW of which must be delivered by 2030, to support the delivery of the UK’s transition to a net zero grid.
“Effective storage is going to be absolutely vital but the current system doesn’t really value storage and flexibility in the way it needs to. A lot of the system is done on an hour-long basis and needs to be upgraded for a world where you have big swings in generation,” says Josh Buckland, who worked as special advisor to ex-business secretary Greg Clark.
So, what are the policy and regulatory hurdles holding back the development of energy storage facilities and how can they be overcome?
Space for all technologies
The nature of these barriers will depend on the technologies and the duration of storage they are designed to deliver.
“There is space for all technologies but they have different operational and economic characteristics,” says Hull, who was the author of a recently published report for Scottish Renewables on the financing of long-duration storage projects such as hydro power stations.
A big source of potential storage will be delivered via the batteries on wheels which are set to increasingly flood the motor market as the 2030 ban on sales of internal combustion engine cars and vans approaches.
Tariffs already exist that enable households to charge their electric vehicles (EVs) when electricity is cheap and discharge it back to the network at peak times.
However, the wider electricity system is not sufficiently well tailored to encourage consumers to switch to such tariffs, says Buckland: “At the moment on a domestic level, it’s quite difficult without smart meters and half-hourly settlements to get full value from that storage by providing services to the grid as a consumer. You need the regulatory system to adapt to really support those half-hourly settlement and potentially other changes.”
And while these individual EV batteries will potentially add up to a massive amount of storage, they cannot be depended on to keep the lights on, says Hull: “The advantage of large-scale storage is that you can assure its availability, EVs are not as reliable as purpose-built storage plants.”
Here there is good news with total operational battery storage capacity having increased from 0.7GW to 1.1GW in just over a year, according to figures published by RenewableUK in February.
Cara Dalziel, policy manager at Scottish Renewables, says: “We’re seeing batteries coming through in quite big numbers.”
The Capacity Market has contributed to this growth, says Buckland: “That part of the market is developing quite quickly on a merchant and capacity basis, which is brilliant because it means a lot of storage can come through without additional support.
“The battery market should take care of itself to some extent, there is no strong case for additional subsidies.”
Market structures
Renewable UK’s statistics also show that around 16.1GW of battery storage is in the development pipeline across the UK – an eight-fold increase since 2012.
Of the total pipeline, while just 0.6GW of capacity is under construction, another 8.3GW is consented.
“It’s not far off what is needed but we’re not it seeing come through to development because we haven’t got the market structures right,” says Barnaby Wharton, the trade body’s director of future electricity systems.
He believes it is “critical” that storage continues to play a role in the Capacity Market because this technology enables the grid to access power at crucial times.
The Capacity Market can’t be relied on though to deliver the volumes of storage required to aid the transition of the energy system to net zero, says Wharton: “It’s not what it is designed to do. The Capacity Market has a very specific role and is not going to bring the levels we need.”
The “key barrier” to getting schemes from consent to construction is the network charging regime, which applies essentially the same set of rules to storage and generation.
These incentivise the development of infrastructure close to where demand is greatest.
But this approach makes less sense for storage, where it is important to locate facilities at pinch points on the network, says Wharton: “At a time when we are trying to deploy storage in areas where there are grid constraints, we are seeing network costs that will discourage that.
“We should be incentivising storage to go to places where there is high congestion and enable generation that can’t get through the grid to be stored for later.
“You are disincentivising storage in areas of high generation and high congestion where you want to use it to avoid congestion on the network.
“The most important thing is to get the charging regime fit for the future and the current regime isn’t going to do that.”
Pumped hydro
These locational problems are amplified when seeking to develop pumped hydro projects, which remain the most tried and tested form of storing electricity long term.
Due to their scale and nature, such facilities can only be developed in a few parts of the country, including the Scottish Highlands and Snowdonia.
“You can’t incentivise changes in location because they are fixed,” says Wharton.
While batteries are useful short term, the technical limits on how long and how much power they can accommodate means that such longer-term options will be required for those periods when wind speeds will be low or even non-existent.
Other long-term storage technologies, such as liquid or compressed air, show “great potential” but are still at an early stage of development with challenges likely to emerge as they scale up, says Hull.
This means hydro stations, which work by pumping water uphill when power is cheap and then releasing it to generate electricity when required, look set to play an important role in maintaining the stability of the grid.
Increasing the number of these plants from the current total of four could replace the gas plants that currently play a valuable role during times of high demand, says Hull.
However, pumped hydro projects, like nuclear and tidal lagoon power stations, involve heavy upfront capital expenditure. They typically take around five to eight years to build, according to the Scottish Renewables report.
“To get those price signals for such a huge capital investment at merchant risk is difficult,” says Hull.
And with electricity prices expected to become more volatile, it will be difficult to provide the guarantees investors want in order to raise the hundreds of millions of pounds such projects require, he adds.
The “biggest barrier” to the development of pump storage is investment, says Dalziel: “The current market design means that we don’t have long-term signals to give that certainty.”
“We haven’t built any for a long time: at the moment, we don’t have financial framework to bring forward storage,” says Buckland.
In his recent report for Scottish Renewables, Hull suggests that long-term energy storage could benefit from a similar support mechanism to that available for interconnector projects.
This would provide operators of pumped storage projects with a minimum level of income, says Hull: “If it went below that, there would be a top up.”
This support may never have to be triggered but would supply a level of guaranteed revenue to give investors confidence that the project is financeable, he says.
“This is more about price stability than outright subsidy,” says Dalziel.
In turn, customers would benefit from the lower cost of capital that would be realised from putting these guarantees in place.
Where this gets complicated for the government is how the value for money of such a mechanism compares to other options, says Buckland.
For example, a big breakthrough in battery storage that enabled this technology to be delivered much more cheaply at large volumes could erode the economics of pumped storage.
Tim Lord, senior fellow at the Tony Blair Institute for Global Change, worries that technological development mean that new financing mechanisms could create another set of “perverse incentives” that are difficult to anticipate.
Hull though hopes that the government will develop a tailor-made support mechanism for long term storage when its ‘Smart Systems and Flexibility Plan’ is updated later this year.
Given the long lead in times for building hydro projects, he warns that the risk of inhibiting the rollout of renewable generation means there is no time to lose.