Long-duration storage, the iGrid and the quest for constancy

Although there is no silver bullet to clean energy’s intermittency problems, sub-sectors within the energy transition are ready to meet the challenge.

When COP21 was held in 2015 and the historic Paris Agreement was signed, more than 99 percent of global energy storage capacity was made up of large-scale pumped hydro projects, according to the Australia-based Energy Storage Council. The road towards a world filled with renewable generation and backed up by batteries was beset by economic and technological uncertainties.

As COP26 began in 2021, total installed battery storage capacity stood at more than 17GW, compared with only 0.7GW six years previously. The UK and Indian governments brought the Green Grids Initiative to the COP26 floor, proposing a global grid that could integrate billions of interconnected rooftop solar panels, wind turbines and storage systems. With a global system like that, it would be fair to say many of the uncertainties of 2015 have been overcome.

“Things really started to accelerate in 2018 and 2019,” believes David Scaysbrook, co-founder and managing partner at Quinbrook Infrastructure Partners. “The last three years have been nothing short of extraordinary.”

That has been noticeable with Quinbrook’s investments. The group placed more than just a bet on storage when it went to Nevada in 2019 and invested in the $1 billion Gemini project – a 690MW solar scheme coupled with a 380MW battery storage system, all wrapped up with a 25-year power purchase agreement with a subsidiary of Berkshire Hathaway. In October, the firm looked to repeat the trick in the UK by investing in Project Fortress, a 350MW solar-plus-storage scheme. Both projects are expected to be among the largest solar-plus-storage developments in the world.

“There is an ability to enhance the capabilities of the grid by using software to manage this better. That’s not something we invest in. We invest in physical infrastructure”

Marco van Daele
SUSI Partners

One key reason for Quinbrook being able to do this has been the growth of electric vehicles. This has increased the production and reduced the cost of batteries, with cheaper manufacturing in China playing a key part.

“Cost was the greatest prohibitor and then, as the cost became cheaper, you could actually use bigger battery banks and therefore have longer duration,” says Scaysbrook. “It’s that inflection point where you could have more of a use case that was more of an energy arbitrage model, rather than frequency response that got paid a higher per-unit revenue but for a shorter period.”

Marco van Daele, co-chief executive and chief investment officer at SUSI Partners, agrees that growth in the EV market has led to significant economies of scale for the battery storage market.

“Battery technology itself has not changed dramatically,” says van Daele, whose firm began raising the world’s first energy storage fund in 2017 and in October completed deployment of the €252 million vehicle. “There have been gradual improvements in the efficiencies of the batteries and the materials being used, but that doesn’t fundamentally provide a step change yet.”

Contractual complexities

Quinbrook’s 25-year comfort blanket with Nevada’s NV Energy is not a common feature of battery storage projects, particularly in standalone schemes that are not coupled with solar generation. This can make battery storage a difficult sub-sector for infrastructure investors to grapple with, depending on their time horizons.

“In 2015 and 2016, I thought we would have an asset class that would follow much more in solar and wind’s dynamics than it has,” says Gore Street Capital’s chief executive, Alex O’Cinneade. His firm manages the London-listed Gore Street Energy Storage Fund, which has raised more than £220 million ($281 million; €245 million) and has an operational portfolio of 210MW. “I expected much more long-term contracts with probably a lower rate of return,” he says. “We had a limited amount of those types of contracts.

“What we have in 2021 is seven to nine different types of [grid] activities, all with different types of contracts available. We have a much wider group of opportunities for us to make money with the same asset class, but those opportunities are ones which have a pretty short duration contract available to them. We’ve broadened the revenue streams, but those revenue streams in terms of duration have got shorter.”

Individual investors’ comfort levels with battery storage investment will depend on the oft-asked question of what represents a long-term investment. Van Daele says these range from three to seven years, depending on the market, but that the regulatory systems underpinning such deals are getting better for investors.

“On the regulatory front, we have seen a few improvements,” he says. “In the ‘front of the meter’ segment, we have invested in the UK, Ireland, Ontario and Australia. One thing that is very clear is regulators have realised the necessity and value of having flexible storage on systems that are taking an increased amount of intermittent renewable generation, and all the difficulties that causes on a grid not designed for it.

“There are movements on how batteries can be better remunerated. We have seen capacity contracts in the UK now applicable for storage, the DS3 programme in Ireland, [and] some developments in Germany and Italy which provide different regulated revenue streams. What they have in common is the recognition that batteries are the most flexible and scalable technology and are needed to enable the increased penetration of clean power generation capacity.”

Bronze bullet

Although the change since 2015 in how storage is perceived within the energy market and the investment world is clear, there remains a widespread lack of knowledge about what batteries can do for an increasingly volatile grid.

“We simply cannot add [to] our targets on renewables without more storage,” says O’Cinneade. “We need it to balance out the intermittent nature of renewables. This year we’ve had a low wind year globally. Wind is underperforming. That will average out, but it is variable. We need it not only on a daily basis, when there might not be enough electricity coming from wind, but also a minute-by-minute basis as wind fluctuates against gas power and that causes the actual grid to be shaky. The grid is not good at dealing with volatility.”

Scaysbrook believes “the use cases for batteries are now exploding” and says volatility is being addressed in a totally new way with grid-scale projects like Gemini and Fortress.

“Now they’re getting beyond ancillary services and fast frequency response,” he says. “We’re now getting into configurations like Gemini. Here we have longer duration batteries, where we can charge them with solar during the day by oversizing our solar project, so they have pure renewable energy. In the early evening when power is most expensive and the sun’s gone down, Gemini and Fortress let you do a three-to-four-hour discharge. Then we’re in a totally new territory for batteries. The cost can still work and that’s a phenomenal change.”

Storage was part of the solution – despite there not being enough of it – in August 2019, when a bolt of lightning caused a failure at the UK’s Hornsea One offshore wind farm. The facility was operating at 799MW, but de-loaded to 62MW; it also caused a tripping at a 749MW combined-­cycle gas turbine plant. Some 1.9GW of generation was suddenly off the system for up to 50 minutes.

“All grids have a technical obligation to maintain a certain frequency and that is tightly regulated,” van Daele notes. “If you go outside that, the system starts to shut down. Either you have a very sudden demand spike or demand drop, where a large power plant shuts down and batteries are very good at plugging that gap. It just depends on how you get paid for it.”

The lightning strike was a perfect example of the grid-scale use case of battery storage. It is not, however, a silver bullet. Contrary to some claims at the time, battery storage would not have been of help in power failures in 2021 such as those resulting from the Texas storms and Europe’s autumn energy crisis.

“If you have a one- or two-hour battery and you discharge, that’s it,” maintains Scaysbrook. “You’re prohibited from recharging the battery because… that’s putting demand on the system. When everyone’s desperate for every MWh they can get, they don’t want something charging and then discharging again. A gas turbine may be expensive, but you can run it around the clock.

“Until they become much longer duration, batteries are completely useless for something like we experienced the other month. Cost-effective, long-duration energy storage will happen. We are in that waiting period, but it’s worth waiting for.”

O’Cinneade provides slightly more cautious optimism on the ability of storage to mitigate such troughs, although he believes it can be done.

“Is storage going to solve peak demand? The right amount can, but that would need a very significant amount of storage,” he says. “We would fill our systems up at 2am when prices were low and deliver the electricity at times of peak. If there was enough storage on the system, there would be no peak, but that would require a bigger build-out than is already underway.”

Welcome to the iGrid

A nascent but burgeoning part of enabling more storage to come on to the grid and mitigate the intermittent nature of renewables is the smart grid – the supply of electricity through digital communication.

The build-out of smart grids was underlined in November, when Blackstone invested $1 billion in Ohio-based utility FirstEnergy. Quinbrook has also invested in UK-based smart grid operator Flexitricity.

“Cost-effective, long-duration energy storage will happen. We are in that waiting period, but it’s worth waiting for”

David Scaysbrook
Quinbrook Infrastructure Partners

“Data and machine learning and AI are going to play a huge role in the optimisation of power grids,” says Scaysbrook. “There are so many variables to a modern power system stacked with weather-dependent renewables. It is beyond the capability of a traditional, centrally controlled power system operation like [the UK’s] National Grid to manage all of that without a lot of assistance that just can react much faster than people can.

“We are moving to a world where power systems are automated – I don’t think there’s too much doubt about that. Smart grids will be smart because they’ll be able to operate seamlessly with the automation of that power system. We think there’s a high probability this will be accomplished in the next decade.”

However, van Daele is more reluctant to see this as an infrastructure play, instead choosing to focus on the build-out of smart meters.

“There is an ability to enhance the capabilities of the grid by using software to manage this better,” he says. “That’s not something we invest in. We invest in physical infrastructure.”

Although smart grids are also out of range for the Gore Street fund, O’Cinneade believes the shift to a digitally enhanced grid is the future of energy distribution. “The idea of a smart grid, which is where we’re definitely moving, is it is an integrated whole and we can address problems such as load demand, intermittency and be able to take on more renewables in a comprehensive way,” he says.

As with battery storage back in 2015, it may well require the brave to take those leaps forward for everyone else.