The UK’s first grid-scale battery – a 6MW/10MWh facility at Leighton Buzzard – was opened by UK Power Networks (UKPN) in April 2014 as part of an Ofgem-funded innovation project.
Since then, the market has expanded exponentially, with batteries experiencing their real breakthrough moment in 2016 when more than 200MW won contracts in National Grid Electricity System Operator’s (ESO) trial of a new sub-second Enhanced Frequency Response (EFR) service and then later that year 500MW secured agreements in the four-year-ahead Capacity Market auction.
Their progress was slowed slightly by the subsequent introduction of lower Capacity Market de-rating factors for shorter duration batteries but has been bolstered by a series key policy and regulatory changes that have clarified their position within the energy system.
These include a ban on ownership by distribution network operators (DNOs) – UKPN put the Leighton Buzzard facility up for sale a couple of years ago; the classification of storage as a form of generation; the ending of double charging of storage network, balancing and other levies on both import and export; and the removal of the 50MW threshold above which storage projects were previously subject to the Nationally Significant Infrastructure Project (NSIP) planning regime.
The rise of batteries has also been driven by market developments such as the opening of local flexibility markets by DNOs, the ESO’s ongoing overhaul of balancing and ancillary services, and of course, the growth of intermittent renewables, which are ultimately creating the need for the capabilities they provide.
As of February 2021, RenewableUK put the total pipeline of battery storage at 16.1GW, consisting of 1.1GW of operational capacity, 0.6GW under construction, 8.3GW consented, 1.6GW in the planning system and 4.5GW at an early stage of development. Only two years earlier the figure stood at 10.5GW.
Underpinning all of this has been the rapidly falling cost of lithium-ion batteries as the technology matures with the rise of electric vehicles. According to BloombergNEF’s latest global price survey in November, average battery pack prices fell almost ten-fold over the previous decade or so from more than $1,200/KWh in 2010 to $132/kWh in 2021.
However, Mark Futyan chief executive of Anesco, says surging demand for EVs and constraints on supply have put the brakes on this downward trend over the last year: “The real root of it is lithium carbonate prices, which is the first raw material at the very beginning of the whole manufacturing chain. This time a year ago the price was 50,000 Chinese yuan per tonne and it’s now at 300,000, so it’s gone up six-fold.”
Although this “dilutes down,” Futyan says this has still had a significant effect on battery cell prices, which are double what they were a year ago, meaning “a full finished stationary storage project is probably up in cost by about 20%.” He says project costs had halved over the past five years and the recent increase in battery prices has probably set back cost reductions by around two years.
He believes this upward pressure on prices will probably persist for some time: “It takes years to bring a new lithium mine into operation so you’ve got a bit of a constraint on the supply side.
“And then on the demand-side, it’s really electric vehicle batteries that are the source of demand and the growth has been higher than people anticipated.”
“I guess there’s a question of whether a price increase will correct that demand because EVs become too expensive but I’m not sure it’s a materially sufficient component of the car cost to dampen demand.”
Furthermore, he adds: “I don’t think the full effect of the six times increase in lithium has yet flowed through to cells because there’s a time lag along the chain so I think there are more price rises to come.”
Fortunately for the sector, Futyan says this development has coincided with a surge in revenues and growing investor confidence over the future prospects for batteries: “What we’re finding is that even at current prices our investors can still make their economics work because of the expectation of future price volatility and the demand for grid services. And the value of grid services is so much higher than it was a year ago that the revenue side and cost side have gone up together so I think we will continue to see investment in energy storage.
“I think this boom of buildout will continue. It just makes doing business extremely difficult because it’s a very volatile environment where as soon as you’ve lined up a deal across the whole supply chain, then the whole thing has to be torn apart and restarted and that’s just made projects extremely challenging.”
He says the best market for batteries at the moment is Dynamic Containment, the enduring successor to EFR and the first to be introduced in the ESO’s new suite of three frequency response services – the others being Dynamic Moderation and Dynamic Regulation.
As the name suggests, Dynamic Containment was introduced as the first line of defence to contain drops in frequency following a fault. The ESO says the requirement for this service is growing as the inertia of the electricity system – its resistance to sudden changes in frequency – decreases due to the closure of synchronous thermal generators with heavy turbines spinning in harmony with the frequency of the power grid.
After debuting in October 2020, Futyan says Dynamic Containment has quickly moved from being a “niche trial market” to “quite mainstream.”
He says it has also been very lucrative, with those that qualify consistently earning £17/MW/hr – the maximum allowed during normal market conditions – due to the ESO’s requirements exceeding the available pool of batteries: “That’s just given greater investor confidence that the returns are there. Those that have had operational storage assets have had a bit of a windfall from that, which generates some cash, which enables them to invest in more storage assets. All of that is driving high investor demand for this asset class.”
This is starting to change, with the price falling below the cap for the first time in November: “It used to be that the demand from grid was greater than what was installed so everybody just took the price cap, whereas now you’re starting to see as new assets come on, it’s breached that demand and therefore it’s not always the maximum. It depends on the demand on the day, given what’s happening with intermittent generation.
“I think everyone is expecting that as more capacity joins as it will within the next year, without question, the price will come off because there won’t be a shortage of supply.”
Futyan acknowledges that the ESO’s appetite for frequency response does keep growing so it may be a bit longer still before it is fully sated.
But he says the huge pipeline of batteries means the market will eventually become saturated and focus will have to shift towards wholesale arbitrage: “I think there’s probably a couple of gigawatts of grid demand for ancillary services for batteries and the current pipeline of batteries being developed is about 20GW.
“I don’t know how much of that’s going to get built but even if half of it gets built or a quarter of it, it will be way in excess of what grid needs.”
He continues: “We expect more volatility from more wind and solar that brings up the wholesale and the saturation of grid services brings down their value and then the two should equalise. What we expect to see is flipping between those two different options depending on where the optimum value in the market is at that time.”
One very noticeable trend in the battery market has been the growing size of installations.
“We started off in 2014 with our first ones at 1MW and then we started doing 10-20MW and now in general investors are looking for 30MW plus really,” says Futyan. “Below that’s a bit subscale for most of the investors we have who have big pools of capital they want to deploy.”
Futyan says the removal the 50MW threshold for batteries to become subject to the “longer, more complex” NSIP planning regime has seen projects between 50 and 100MW become the new norm.
Although a larger project has already been announced – Sembcorp’s planned 360MW installation in Teesside – he expects most batteries to be no bigger than 100MW: “You don’t particularly get economies of scale above that because you tend to have to connect at a higher connection voltage because the DNOs just don’t have the capacity for much above 100MW and then if you want connect directly to transmission network, you’ve got to wait four or five years to get your connection and you’ve got a very long planning process.”
There have also been moves towards to co-location with renewable generation, with Anesco itself installing batteries alongside its Clayhill development – the UK’s first solar farm to be built without subsidies in 2017. Scottish Power has previously announced that most of its future renewable projects will combine at least two out of the three of wind, solar and storage.
Futyan says there’s “no question” that there are benefits to co-location, which he says can save money in development, planning, connection and construction, and also allows optimisation across assets. But he says the “vast majority” of current projects are still standalone and he expects this to continue to be the case over the short term, for several reasons.
“One is that there isn’t currently market signal to do that.” Given the value of ancillary services, Futyan says it makes sense to focus on those above everything else, meaning there is little motivation to optimise across assets in the wholesale market. He says this will eventually change as the value of the wholesale market increases relative to ancillary services.
“Reason number two is it’s very difficult to find a suitable co-location site. For batteries what you need is both import and export connection at the large scale which is very rare to find. And for solar what you need is a greater big plot of land as close as possible to a substation with capacity for export only.”
He says finding either of these difficult enough but if you want both in the same place “you’ve got to find two needles in the haystack right next to each other and that just makes it really hard as developer.
“I think it’s going to be an enduring issue for greenfield but as we see assets come to end of life and you get to the repowering point for wind and solar farms, I think every project will then relook at it and say is there a co-location opportunity and can we apply for additional import to add to our export.”