Eku Energy: ‘Shareholders understand balance between merchant and contracted revenues’ in Australia’s NEM

Canadian institutional investor British Columbia Investment Management Corporation (BCI) came on board as Macquarie’s joint owner of the developer a few months later, and while it now has a development pipeline that includes projects in the UK, Italy and Japan, its first announced projects were in Australia.

Rachel Rundle, Eku Energy’s senior manager for policy and regulation in the APAC region, tells Energy-Storage.news that the company has more than a gigawatt-hour of assets in delivery in Australia, across three projects with different partners and business cases.

Its first Australian asset, Hazelwood BESS, was built on the site of a decommissioned coal power plant in Victoria, jointly developed with French utility Engie. Construction began in 2021 with the Green Investment Group and Engie financing the project, and Fluence supplying and integrating the battery storage technology.

Commissioning took place in June 2023, marked by an event attended by Victoria’s minister for energy & resources, Lily D’Ambrosio, and the battery asset is operating and trading in the National Electricity Market (NEM) on a full merchant basis for the owners.

Minister D’Ambrosio was again in attendance as construction began on Eku Energy’s next project in July 2023. Also in Victoria, the 200MW/400MWh Rangebank BESS at Cranbourne in Southeast Melbourne is by contrast to Hazelwood contracted to a 20-year tolling agreement with co-development partner Shell Energy.

Oil and gas company Shell’s energy solutions and retail utility arm will trade and operate the BESS in the market over the asset’s lifetime.

Rundle says she can’t speak to Shell Energy’s strategy for how it will optimise the Cranbourne project, but says it is likely that will be a combination of balancing or firming up the utility’s own customer load and trading it across the NEM’s ten separate frequency control ancillary services (FCAS) markets and wholesale trading.

The third project already in delivery is in the Australian Capital Territory (ACT) and was awarded to the developer in April 2023 through an ACT state government competitive solicitation process.

The ACT government pledged AU$100 million (US$67 million) in funding towards the total expected cost of between AU$300 million and AU$400 million from the 2020-2021 state budget before running the procurement tender.   

In this case, the state government will be Eku Energy’s partner for the 250MW/500MWh Big Canberra Battery (BCB), as it is known. The pair will share revenues generated by NEM participation, while the ACT government will also pay Eku fixed sums on a quarterly basis over a 15-year term.

“We very much do look at each asset, at what’s the best for financing outcome at the asset level, but also thinking about the broader portfolio,” Rundle says, speaking at the 2024 Energy Storage Summit Australia which took place in Sydney a few weeks ago.

“So yes, that portfolio has three assets at the moment that are all contracted in different ways, but we’ll be looking at what’s optimal for that asset to get the lowest cost of capital.”

Eku Energy does not have a “hard and fast rule on the level of contractedness” it goes for with each project, with shareholders Macquarie and BCI both having appetite for merchant risk, and understanding the balance between merchant and contracted revenues, according to Rachel Rundle.

Having a broader portfolio view of assets and pipeline means that the developer can “take a higher merchant case in some assets and a higher contracted case in others,” Rundle says.

Differences across NEM jurisdictions

All three projects are in the interconnected states and territories that comprise the NEM, but the market’s different regions, while offering access to the same markets for ancillary services and wholesale trading, will see revenues vary.

“The NEM has five jurisdictions. Five zonal markets, as you might call them in other electricity markets, all with their own spot price. So those spot prices, usually they correlate, but I think what we see when there’s inter-regional transmission constraints, or different supply mixes in different states, we see that price divergence,” Rundle says.

“We’re seeing a bit of that now with the northern states, Queensland and New South Wales having different price dynamics from the southern states, and that sort of changes over time as the thermal fleet comes in and out.”

Therefore, for each project, it’s a case of modelling the revenue case in that particular jurisdiction for the asset.

In terms of the merchant business case, long-term forecasts across all of the different energy products in the NEM need to be taken into account.

As has been seen in other markets such as PJM in the US, the UK and Germany, frequency regulation ancillary services have been the first big opportunity for batteries to participate on a broad scale in the NEM, but as installed BESS capacity grows, those relatively shallow markets tend to saturate.

Rundle notes that the FCAS markets are where the bulk of revenues for batteries have come from in the past.

“But I think as we’re seeing more saturation in those markets, the way we need to operate our assets and develop our assets is shifting towards more of an arbitrage play, and arbitrage being a bigger portion of that revenue stack, and in and amongst that, we’ll have ancillary service revenues, arbitrage revenues, network support-style revenues.”

ESN Premium also spoke to representatives of technology provider Fluence at the Australia Summit, and heard that those network support services could be an important source of revenues, likely contracted, going forward.

Those services today, which include System Integrity Protection Scheme (SIPS) contracts where batteries act as a kind of ‘shock absorber’ to the grid, building in redundancy to cope with unexpected transmission service disruptions, are largely contracted with the transmission operators, or transmission network service providers (TNSPs) as they are called in Australia.

Not every asset across Eku Energy’s Australian fleet may be in the right place on the grid, or equipped with the right technologies such as advanced grid-forming inverters, to provide them, but Rundle says the developer will be looking to bid into those opportunities where it can.

“Those types of services, whether it’s reactive power, or dynamic voltage support, or whatever it might be, some of those services are quite locational in the NEM,” Rundle says.

Australia’s grid is often described as long and “stringy,” stretching vast distances to the rural ends of each line, meaning some parts of the grid require much more strengthening and reinforcement than others.

“Some of those [opportunities] will be very locational, and if we don’t have batteries in that location, then we perhaps won’t win that service,” Rundle says.

‘Natural dynamics benefit storage’

The necessary framework for rolling out system services contracts on a wide scale is yet to be implemented in Australia, whether that be TNSPs holding regular tenders or some other structure.

The contracts that have been awarded, such as the SIPS contracts held by Neoen’s Victorian Big Battery already in operation, or Akaysha Energy’s Waratah Super Battery in New South Wales (NSW) currently in construction, have been on something of a case-by-case basis.

In that sense, it’s impossible to say what the commercial and revenue case for such schemes might look like, Rundle says, but the decarbonisation benefit of putting batteries to work performing such applications, traditionally provided by fossil-fuelled thermal generation, is clear.

“That’s the good thing. We definitely see that with all the system challenges that we as a sector are aware of, through all these thermal plants coming out of the system, batteries are really well-placed to provide those services: whether it be system strength, whether it be synthetic inertia, voltage support, batteries are sort of that multi-tool asset,” Rundle says.

Energy storage can certainly help smooth the transition to renewable energy away from thermal generators, if enough of it is built and in the right places. The only question around that is whether enough can be built in time to meet Australia’s national and state goals on decarbonisation, Rachel Rundle points out.

Going forward, one big challenge will be getting the durations of energy storage right. There is growing recognition that Australia will need significant quantities of storage going to durations longer than the 1-hour, 2-hour and even 4-hour lithium-ion (Li-ion) assets being built today.

The natural dynamics of the NEM’s wholesale market, which has a very high cap and sees negative pricing events, benefit storage already today, but how the market can now evolve to “value depth” is the big question.

“When we’re thinking about those longer durations, we need to think about, what the shape of wholesale price over the day will look like, and then what size storage we need to capture enough arbitrage spread to earn enough revenues through the market,” Rundle says.

The government has already stepped in with the landmark Capacity Investment Scheme (CIS) tenders for firmed renewable generation, which Rundle says is recognition that the market is not yet really delivering wholesale revenue returns.

It’s likely the CIS tenders and future tenders will support getting 4-hour+ durations into the market because wholesale market opportunities today are not attracting sufficient investment commitments to do so.

Eku Energy will be looking at different depths of duration, Rachel Rundle says, looking already at deploying systems beyond the 1-hour and 2-hour durations it has already committed to, noting that Li-ion technology is likely well-suited to providing longer durations at 4-hours and even 8-hours-plus.