A massive electricity price spike in Queensland earlier this month has once again demonstrated how and why gas is fighting a losing battle against battery storage for the key supporting role in Australia’s future renewables grid.
The new perspective comes from Andrew Wilson, who heads corporate energy and sustainability at The University of Queensland (UQ) and oversees the University’s 64MW Warwick Solar Farm and its 1.1MW/2.2MWh St Lucia Tesla battery storage system.
As RenewEconomy has reported, Wilson and his team are leading a world-first initiative for UQ to become a 100% renewable ‘Gensumer’ – playing on both sides of the energy market and using energy storage and demand response to power the Uni flexibly, sustainably, and economically.
In a report published on LinkedIn this week, Wilson writes about the performance of the UQ battery on the morning of Tuesday October 13, when Queensland’s spot electricity price rocketed from an average of around $25/MWh to the market cap of $15,000/MWh, “seemingly out of nowhere.”
As Wilson notes the prices dropped back to $17/MWh in the following dispatch interval, before then hitting the market price floor of -$1,000/MWh for the next two and then settling at $2,179/MWh for the trading interval.
The reasons behind this spike have been the subject of a series of explainers on Paul McArdle’s Watt Clarity and, like Wilson, RenewEconomy will leave the whys to one side for now. Suffice it to say: it’s complicated.
But it should also be noted that price spikes like this are not exactly unheard of on Australia’s National Electricity Market. And nor are they unique to the era of high-renewables grids.
A 2016 Climate Council report, prepared by former Origin Energy executive Andrew Stock, estimated that gas generators reaped a windfall $178 million during a series of price spikes in South Australia as they increased margins and withheld capacity to maximise their profits.
Stock pointed, at the time, to a lack of competition in South Australia and the resultant impact on wholesale and retail electricity pricing. As Giles Parkinson noted here, Queensland was rapidly following suit, with similar revenue hikes when government-owned generators appeared to act in concert to push up prices.
Regardless of what event or which technology triggers the price spikes – and renewable energy is a popular scapegoat – it is what happens directly after the sky-high price signal that interests Wilson, as a “fascinating case study” of things to come as the energy transition hastens.
Essentially, Wilson uses NEM data gathered using Global Roam to compare how the University’s relatively small Tesla Powerpack battery performed during the price spike, compared to the traditional ‘peaking’ plants in the market.
The result – and Wilson stresses that the St Lucia battery is a behind-the-meter asset that isn’t required to participate in the dispatch process, but can behave as it sees fit in response to events as a ‘price taker’, and he accounts for this – falls overwhelmingly in favour of batteries.
Essentially, it finds the UQ battery was able to capture three times more revenue than other peaking plants due to having no start up time, and an instant ramp rate.
“As seen [in the chart] above, the battery is substantially more effective than other peaking plants at responding to the unexpected price spike, and is able to be at full output within 5 minutes of this event occurring,” Wilson writes.
“The absence of constraints on start-up time or ramp rate results in a substantially higher revenue capture – both for the overall 30 minute trading interval, as well as for the four dispatch intervals after the price spike occurred.
“Figure 6 shows a comparison of the portion of revenue captured by each plant compared to a theoretical maximum assuming full nameplate output for the relevant time period.”
In reality, Wilson explains that the St Lucia Tesla powerpack’s autonomous Demand Response Engine (DRE) algorithm responded to the sudden price spike as soon as it was received from AEMO and immediately began discharging for the rest of the trading interval.
“In total it captured around 19.5 minutes out of 20 at full discharge once the price spike was received just after 9:40am,” he writes.
“The battery then swung to begin charging for the following two trading intervals, achieving an average charge price of around $11/MWh. In the [trading interval] ending 10:00 (when the price spike to Value of Lost Load occurred), the battery earnt $786 from discharging – not a bad morning’s work.”
Spinning that real world performance out into a hypothetical, Wilson also took a look at how these events may have played out in a 5 minute settlement scenario.
“Across the [trading interval], ending 10:00, the battery discharged 0.361 MWh, earning $786 in revenue as it optimised its position across the 30 minute settlement period,” he writes.
“On a dispatch interval basis across the same period, however, there is a high probability DRE would have directed the battery to discharge ~0.0925 MWh at +$15,000/MWh in the 9:45 [dispatch interval], sat idle in the 9:50 DI, and then charged ~0.185 MWh at -$1,000/MWh during the 9:55 and 10:00 [dispatch intervals].
“This would have resulted in revenue for the half hour of $1,572 – double what was achieved on a 30 minute settlement basis,” Wilson says.
Wilson doesn’t claim that this one case study amounts to a clear win in favour of batteries, or the death knell for gas peaker plants, rather he points out that it is a neat illustration of where the market is headed, and of how quickly things have changed – and will continue to do so.
“Despite the many questions still remaining about the market response to this event, what is clear is that start-up time and ramp rate constraints placed hard limits on how aggressively the peaking units within the region could respond to take advantage of high prices, and fill the gap in supply caused by the sudden withdrawal of capacity in North QLD,” he writes.
“There’s no doubt that the coming years are going to present challenges for incumbents and opportunities for new technologies, and will certainly be fascinating to watch play out.”
As far back as 2015, international credit rating agency Moody’s Investors Service forecast that battery storage would be economically viable within 5 years in the US market, and the biggest losers would be electricity generators, particularly peaking gas plants.
And in July this year, the Australian Energy Market Operator weighed in on the issue in its Integrated System Plan, painting a scenario where both batteries and gas will play key roles, but ultimately, it will come down to price.
“Gas and batteries can both serve the daily peaking role that will be needed as VRE (variable renewable energy) replaces coal-fired generation, so relative whole of life cost is a key variable for potential investors to consider,” the AEMO ISP notes.
“Gas has a cost advantage over batteries at current gas and battery costs. However, in the 2030s when significant investment in new dispatchable capacity is needed, this advantage could shift to batteries, especially to provide dispatchable supply during 2 and 4-hour periods.
“Based on the cost assumptions in the ISP, new batteries are more cost-effective than gas in the 2030s. Future climate policies may also impact the investment case for new gas.”
Another study, this time from energy consultancy Cornwall Insights Australia, is more blunt: “Battery storage value is a sign to the government that we don’t need more gas-powered generation,” said Ben Cerini, one of the lead consultants to the report.
“Batteries are dispatchable, they now compete with GPG as peaking assets in their own right and are winning in huge capacities (in auctions in the US). With new markets emerging in the NEM, it will not be long before projects like this begin to look feasible in the Australian market.”
Whether the Australian government is seeing this sign is another matter entirely.
