The UK needs energy storage. That much is clear. The transition to a net-zero emissions economy requires a decarbonised electricity supply.
But the market for storage is far from fully formed, according to market players and other stakeholders at the recent RenewableUK Storage 2019 conference in London.
The UK’s energy-storage pipeline is growing, from a 6.9GW pipeline in 2018 to more than 10.5GW today, according to new figures from RenewableUK, most of it featuring lithium-ion battery technology.
Yet, the business case is still far from clear-cut, and earning revenue from batteries can feel like a puzzle.
From 2025 the economics for energy storage look good, as more low-cost wind and solar capacity is built and revenue opportunities from arbitrage increase with the widening gap between cheap and high wholesale prices.
Based on its future energy scenario modelling, the UK’s electricity system operator (ESO), National Grid, expects the country will have around 150GW of installed generation capacity by 2030, compared with just over 100GW today.
More than half that total will come from wind, solar and other renewable sources. Peak demand will be roughly the same as it is today, at 50-60GW.
As the UK continues to add more renewable capacity to 2050 and reduce thermal generation capacity, periods of oversupply could rise from 2-3TWh in 2030 to 20-25TWh after 2040.
By 2050, National Grid ESO forecasts installed electricity-generation capacity to exceed 200GW, with renewables accounting for 150GW of this, and energy-storage capacity amounting to 30-50GW. Peak demand will barely increase.
"By 2050 there will be lots of spikes, as much as 50GW of excess capacity on the grid in summertime, with large volumes of low-cost energy available," said Marcus Stewart, National Grid ESO’s principal adviser for energy strategy and policy.
National Grid ESO has also modelled how the system will operate in 2025 based on a zero-carbon electricity mix, which Stewart says is similar to its lower-carbon scenarios.
Most of the energy-storage capacity connected to the grid between 2017 and 2019 is deployed to provide frequency regulation and the capacity market.
There will be more need for frequency regulation-type grid-balancing services as electricity generation is decarbonised in line with the system operator’s forecasts.
Limited revenue opportunities
"There is a big question mark over revenue streams. Where will that certainty come from?" Jack Steven, senior operations manager at investment-management firm Foresight Group, told delegates. Foresight’s grid battery assets are mainly playing into the enhanced frequency response (EFR) and capacity markets.
While 2018 was a record year for storage capacity commissioned, with more than 450MW coming online, last year just over 100MW was commissioned, less than in 2017, RenewableUK’s recent figures show.
According to Marina Valls, the trade body’s chief economist, there are consented grid battery projects, but there is a "wait and see" attitude, which could change when the capacity market auctions start again in 2020, following the market’s reopening.
The European Commission temporarily halted the UK capacity market — the mechanism that ensures enough power will be available at peak times — in November 2018 pending an investigation into its compatibility with EU state aid rules.
Other new revenue opportunities include distribution network operators (DNOs) tendering for capacity on the distribution grid in local balancing markets.
While construction costs of battery-storage projects have fallen, investment managers all have different criteria, Steven pointed out. "Lenders do need to be involved.
But not having a clear sense of how their payments will be serviced is putting them off," he told the event.
"There’s a lot of ‘noise’ around storage, such as the suspension of the capacity market, and that can make lenders nervous. Before looking at financial models, you have to consider the perception of energy storage."
National Grid ESO modelling points to more arbitrage opportunities in the next few years.
However, battery storage systems connected to the grid have been designed primarily to respond to frequency regulation signals, which is a different operation compared with targeting arbitrage opportunities in the wholesale market.
Any significant change in how the storage system is used could impact battery warranties.
The National Grid has been working on widening access to the balancing mechanism, one of its main grid-balancing services, traditionally dominated by large generators.
Battery assets have been able to access the market via aggregators. However, many of the Electricity Storage Network’s members have found the market is still not set up for storage.
National Grid ESO is going to carry out a programme of work in the next few months that includes looking at the balancing mechanism to better facilitate energy storage, according to Stuart.
Progress on the policy front should help streamline projects’ development phases. Last year, the Department for Business Energy and Industrial Strategy (BEIS) agreed to change consenting rules that had been deterring development of projects over 50MW in size.
Under BEIS’s proposals, energy-storage projects (except pumped hydro) will be consented by the relevant local authority, exempting them from the national regime.
The results of the first rounds of auctions by DNOs last year, to provide flexible capacity to support the electricity distribution network, have shown how increased flexibility on the distribution grid can counter the need for network upgrades, saving on costs.
Following initial auctions, Piclo analysed the breakdown of flexibility providers. Piclo’s platform enables DNOs to procure flexible capacity from technologies including battery storage and demand response aggregators to defer reinforcement works on their local electricity networks and improve resiliency.
Just 19%, or 842MW, of capacity uploaded by June 2019 belonged to large batteries of 1MW of more, while generators accounted for 77%. Generators are most likely to deploy fossil-fuel production from gas or diesel engines, supplemented by combined heat and power, waste-to-energy, and some wind farms.
The biggest winners of these first tenders are mostly generators relying on fossil-fuel power assets, rather than new entrants deploying zero-carbon solutions such as energy storage or demand side management, the Electricity Storage Network points out. In time, this should change as fossil-fuel generation is phased out.
At first glance, the expanding pipeline of energy-storage applications and the growing number of entrants looks like a strong market. And in many ways, the UK is a leader in Europe. By comparison, Germany has one market — primary control reserve — providing a grid-balancing revenue stream for storage.
Financing projects is challenging, due to a lack of long-term visibility and risks.
There is no cookie-cutter storage business model. Relying heavily on a revenue stream such as FFR and short-duration contracts is too much risk for many lenders to bear, while promising markets such as the balancing mechanism still require fine-tuning for storage to be able to capitalise.
"There are lots of projects consented, though waiting for investors has been slow until this summer, when we have started to see renewed interest," said Tracy Scott, delivery project manager for new technologies at developer RES.
"This is partly because investors with batteries in the EFR and FFR markets are comfortable with the technology, coupled with battery prices continuing to come down in the past two years."
Although the need for flexibility is well understood, forecasting revenues under uncertainty is difficult, and investors that are seeking third-party financing require more certainty in order to advance projects, according to Simon Williamson, commercial manager for energy storage at London-based Kiwi Power.
To help address risks for the battery-asset owners in its aggregation platform, Kiwi Power has been developing battery floor pricing to guarantee a minimum revenue level.
Other options on offer include tolling, which reduces the risk to investors to a minimum level, with lower long-term revenues. Investors with more appetite for risk need to look towards market diversification, with more of a merchant risk model, which achieves the highest revenues but is the least bankable.
Mark Henderson, chief investment officer at Gridserve Sustainable Energy, thinks lenders need to be more creative and agree to seven or even five years rather than look at longer terms for financing.
"We’re just at the start. Batteries will be financed, and then they will be refinanced and refinanced. As we gather more data from operational battery systems about how they perform, the easier it will be to refinance these assets in future," he told the conference.