Habitat Energy takes on fourth Gresham House battery storage site

Habitat Energy has added the 22MWh  Lockleaze battery to its  platform – the fourth Gresham House battery it is optimising.

Habitat has been optimising over 100MWh of Gresham House batteries since February 2020 and is the batteries in NGESO’s Dynamic Containment product and in service and wholesale markets.

This agreement  brings Habitat Energy’s battery storage contracts this year to 225MWh , in which time it has entered the Balancing Mechanism via the Virtual Lead Party route.

Ben Guest, managing director at Gresham House New Energy said, “It’s good to extend our relationship with Habitat Energy to our Lockleaze project. We divide our storage projects between a range of optimisation partners and – as this move shows – are comfortable moving to the best partner for our assets.”

Habitat Energy provides an optimisation and trading platform for grid-scale battery storage, with full route-to-market capability for wholesale and balancing markets in the UK.


In 2019, New Power editor Janet Wood talked to Habitat Energy’s Ben Irons about how the changing structure of the power sector means there can be significant change with little notice. Read the full interview below

In September Drax Power won development consent for a new 300MW gas-fired power station (see separate story). It is the kind of new power asset with which the industry is very familiar and it has followed a familiar timeline: several years of development, more than a year of examination by National Infrastructure Planning and now, following the secretary of state’s decision, a financial close and construction process that could see the plant available on the system by late 2022.

But that familiar process is now not the only way that the system can see the addition of hundreds or thousands of megawatts of new assets. In the industry’s new structure, with a raft of investors, with fleets of small-scale projects, small changes in regulation or market rules can trigger a wave of investments that come into operation within months.

Such assets may be planning to offer services to specific parts of the market, or stack revenues from several sources and they are backed by a variety of different investors. But each could be deployed and available to the system much faster than a new large centralised asset.

Ben Irons I spoke to Ben Irons, co-founder of Habitat Energy, about three waves of pent-up development that could be unleashed.  The company is an optimisation and trading platform for storage and he sees three changes that could cumulatively bring thousands of megawatts of new fast-acting flexibility to the system.

The first is a market change. Batteries have a number of services that can be offered to the market, including frequency response, but for those wanting to trade as merchant power producers there are three markets: day-ahead (an exchange-based market with two auctions per day); intraday (also exchange-based, but with bilateral continuous trading) and the balancing market (BM). The BM is a bilateral market, which arises after so-called ‘gate closure’ – the point, an hour before dispatch time, when other power trades end, and buyers and sellers should be in ‘balance’. The BM fine-tunes the match between supply and demand and responds to last minute changes and the system operator, National Grid ESO (NGESO) is the only buyer.


Where is the value?

About half the value in the market for batteries comes from day-ahead and intraday trading, while half comes from trading in the BM. If the BM worked better it would have much more of the value but it traditionally called on large plant, including hydro pumped storage, to fulfil its needs. Evolving the system, so the ESO can call on new types of smaller, cheaper assets, has been slow and troubled. To get the best outcomes NGESO will regularly have to call on a couple of hundred small units that could help dispatch within a five-minute period and “It can’t be done manually,” says Irons. But the industry has waited years for the outcome of work at NGESO to upgrade its IT systems and improve its ‘merit order’ decisions so that NGESO can call on the new small assets ahead of large old ones.

There is some way to go before the BM becomes more fit for modern purposes. But while waiting for dispatch systems to catch up with assets available, Irons proposes an interim solution. That is to allow for so-called imbalance chasing (properly, net imbalance volume or NIV chasing).

This arises because even with the BM in play, at the point of dispatch there can remain some over or under supply and the ESO has to adjust by paying parties to adjust. That cost is charged to the parties that are ‘out of balance’, so they are incentivised to get it right, and paid to those who over or under-suppled in a way that helps bring the system back in balance. Doing that deliberately, “Doesn’t get taken very seriously by National Grid or potential investors as a viable optimisation strategy,” Irons says. But “It saves [NGESO] from having to individually dispatch assets, which they are struggling to do when it comes to very small, very fast-acting assets”.

One reason it can be implemented quickly is that operators can make their own decisions about whether to be out of balance. “Why not let us self-dispatch,” Irons says, “and have it as an extra angle to be exploited?”.

Operators can make their own decisions about whether to be out of balance. “Why not let us self-dispatch and have it as an extra angle to be exploited?”

At the moment, plant cannot be registered as a BM party and NIV-chase. But Irons says, “If NGESO is not able to manage the BM in a way that fully exhausts all the system need, due to software constraints, or lack of visibility, or forecasts that can’t keep up with the sophistication of new assets, [NGESO] has nothing to lose by allowing asset owners or optimisers to unilaterally help them outside the system rules.” He has suggested that option to NGESO and found the SO ready to listen to the proposal, he said.

That is a tweak to the market that could take effect quickly. If it did, Irons thinks a “vast volume” of investors are ready to install new batteries, with sites in place, EPCs lined up, warranties designed and planning set to go. It will happen quickly, he says, because it is just an addition to the investment case: these projects, typically distribution-connected batteries, are “Waiting for the investment model to get a bit more certain or the returns to get a tiny bit higher to justify the risk.

“..We estimate that there is at least 500MW and possibly as much as 1000MW that could be deployed within a year. It is just waiting for NGESO to tweak these levers by a tiny amount…. The slightest improvement could unleash a wave of investment”.


Riding the waves 

There are other changes that could make more of fast storage in the market, such as using smaller dispatch periods – as short as five minutes. That way the system operator and market participants can better predict supply and demand, and batteries could manage their state of charge better. That looks more difficult. In fact, the UK has fought against some initiatives that would have made the market more granular.

For example, the EU wants national markets to move to a settlement period of 15 minutes, instead of the 30 minutes currently used in GB, to fit in with the EU Internal Energy Market’s ‘TERRE’ cross-border balancing arrangements.  Some European markets already operate on this time window. But the change comes with high set-up costs, and in 2016 the UK won a derogation from the requirement, arguing that the overall cost to consumers outweighed the benefits. The UK made the same case earlier this year, when the Clean Energy Package became law and the derogation had to be renewed.

Irons suggests that the second wave of new capacity will arise from a change of view – this time on the part of solar farm developers, when they decide to co-locate with battery storage.

The market model for co-location is not focused on charging the battery during peak daylight hours, so the power can be sold during peak price hours, to protect against price cannibalisation. “That model is not investable for storage. It’s miles from being in the money,” Irons says. Instead, owners have to look at a more complex investment proposition. Solar will be dispatched while it is being generated, but at other times, when the operator knows the PV will not be generating, the battery can be used to provide flexibility.

A co-located site would be cheaper because the PV and storage share the cost of the connection, and possibly the inverters. And with those revenue lines in prospect, it also makes it worth operators’ while to oversize the PV further (most are oversized slightly) which makes the connection more cost-effective and means better load factors.


Attracting investment

What is required to bring that wave of investment forward? That is investor education, says Irons. Whereas in the past owners would have a single power purchase agreement, instead “the owners would be optimising assets on a minute by minute basis. That idea is completely new,” says Irons. But once they are comfortable with the idea, he believes developers will see it as a way to realise many more projects. “They want to deploy large amounts of merchant solar. All are looking at 50-100MW type investments and most are looking at co-locating storage,” he says.

That immediately raises the question of existing PV farms, some of which are currently constrained off at peak times. Is it worth adding storage? It is not as immediately positive as it may appear, he says, as the electrical and physical configurations may make cost sharing as in new sites (such as sharing inverters) impractical. Nevertheless, it has big potential, Irons says. This time the barrier is in sites’ agreements with the distribution network operators (DNOs). “That requires a two-way connection”, he says, so solar farms can import as well as export. That does not fit with DNOs’ connection agreements or hardware protection systems, which generally assume one way traffic. Neither the plant operator nor the DNO can take advantage of a co-located battery, even if its action (such as importing at peak times) might benefit the local system.

Tapping into that potential is a longer and more cautious process but it could still see a queue of projects forming if a DNO were to begin re-examining its options for existing connections – the type of upgrade that might be picked up and funded under the industry’s Network Innovation Allowance intended to fund smart systems research and development. Pressure is certainly building on that option.

Any one of the three ‘soft’ changes above could see a wave of new assets available to the market.

Any one of the three ‘soft’ changes above could see a wave of new assets available to the market.  Other market participants may see different options than Irons, where other market or regulatory changes are enough to get a fleet of small projects over the investment line. What is clear is that small, replicable projects can be built at scale and quickly if the conditions are right. But fundamentally, Irons says, releasing pent up investment means “We could have hundreds of MW built years earlier than we expected”. The fact that new investment is not in the form of a large central asset making its slow way through the development process does not mean it is not a significant addition to the market – and one that can come online between one winter and the next. In traditional power industry terms, that is the blink of an eye.