It’s hard to plan ahead when forecasts about the clean energy transition change every day. Academic Dr Roger Dargaville talks to Jeremy Chunn about murkiness in the deep reservoir of research and the role he sees for large-scale energy storage.
Forecasting, forecasting, forecasting. Where would the renewable energy industry be without it? To build the right projects today, you have to try to understand how they will fit into the energy mix tomorrow. But different studies which estimate the effects of replacing coal-fired generation with clean energy sources in the future have arrived at different conclusions, with emphases on different technologies.
When massive budgets are in play and so many emerging technologies are changing so quickly, there is enormous risk in misinterpreting forecasts as facts.
Dr Roger Dargaville, senior lecturer in renewable energy at Monash University, calls it “the murky crystal ball of 2050”. For those who will command the investment and policy decisions about which new plants will be built where, a lot hinges on the difference between taking a probabilistic or deterministic approach to research, he says.
“The trick is to run a very large number of simulations that then will tell you what the best course of action is that hedges you against the risk of different things happening,” Dargaville says. “If your competitor’s technology is going to become significantly cheaper than yours, then you could be in trouble. The trick is to work out what’s the risk that they’ll undercut me.
“Depending on what that chance is, you make that decision by looking at the spectrum of potential outcomes.”
That’s all very well, but decisions are made today based on models that, if they were continuously updated with fresh data, might recommend different outcomes once certain thresholds are breached. The future is unpredictable – no-one’s disputing that – and researchers prefer to call outcomes of modelling “projections” rather than predictions, for good reason. When it comes to modelling a transition to increased reliance on clean energy generation in Australia, things can get very complicated. “You try to do the best set of assumptions you can,” Dargaville says, which is tough when you don’t really know, for example, the cost of concentrated solar thermal, pumped storage, geothermal or to build a nuclear plant in Australia. “These are very rubbery numbers.”
But there’s a silver lining to the conundrum. “On the upside, the good news is it means there is a lot of flexibility in the market; we’re not locked in to a certain pathway.”
EcoGeneration spoke to Dargaville during the Clean Energy Council Pumped Hydro Roadshow in Sydney in June, which included presentations from GE and ARUP that gave some indication of the challenges of identifying sites and building underground generators. With a hundred years’ of history, there must be a high level of certainty around any assumptions around data from pumped hydro included in modelling, right? Sort of, says Dargaville. “We’ve got a pretty good handle of what will happen to the cost of pumped hydro in the future,” he says. “And the answer is it’s not going to get any cheaper … whereas the emerging technologies you expect to be coming down in price relatively rapidly if they can reach those thresholds and start to be deployed.”
The round trip
Pumped hydro consumes energy, with a round-trip efficiency of about 70-80%. The only economically rational reason to build it is to profit from the price differential between when it consumes and generates power. As more and more renewable energy projects come online, and the cost of electricity falls to reflect an increase in supply, that price differential will narrow – in theory. The fact that new supply will be generated by wind and solar plants of course means that intermittency will become the ogre in the markets. “Because there is more volatility in the wind and the sun than there is in a coal-fired power station, you end up with more events where your peakers are having to step in, and the peakers set the market price very high.”
Pumped-hydro peakers are a viable option, although development will have to be at a scale that does not endanger the arbitrage opportunity that encouraged it in the first place.
Dargaville cites simulations of 100MW and 250MW projects at the Cultana site on the coast of South Australia, where it was found a 250MW facility would have lower earnings per megawatt hour because some of the arbitrage opportunity would be removed. “It becomes an economic decision as to whether it’s cheaper per megawatt hour to build a 250MW project if that scale of economy offsets the reduction in the revenue stream.”
Dargaville backs centralised generation as the more cost-effective way of building a renewable system, such as large-scale solar and wind plants with centralised storage. “Distributed rooftop PV and batteries are nice to a certain degree but they are relatively expensive,” he says. “The reason they look cost-effective to consumers is because they are on a retail tariff that is not really cost-reflective of what it costs to generate electricity.”
Consumers pay a variable charge about 25c/kWh, whereas the wholesalers pay between 8 and 11c/kWh. Retailers fold a lot of fixed costs into the variable charge, he says, and a cost-reflective tariff would be more like 7 or 8c/kWh – and PV would not be cost-effective to offset it.
“We’ve got this market perversion that encourages rooftop PV and is starting to encourage batteries,” he says. “If you have a top-down system and you optimise generation mix you don’t put rooftop PV and batteries in.”
Centralised versus distributed
If owners of Australia’s 1.6 million rooftop solar PV systems decide to not replace their gear at the end of its life, Dargaville says a grid made up of efficient centralised renewable generation and storage will have no problem filling the gap. “Anything you build has a fixed lifetime and has to be replaced with something,” he says. “If utility-scale PV is cheaper per unit [of energy] then that is what should be done.”
As for placing too much hope in utility-scale storage provided by rows of shipping containers packed with exotic chemical solutions, he says the technology is good for fast frequency response but not for providing inertia that is correlated to the spinning rate of generators.
When frequency drifts away from 50Hz utility-scale batteries can provide a pulse either injecting energy into or extracting energy from the system to get the frequency back to 50Hz, he says, but they fall short when relied on for too much.
“I like the analogy of riding a bicycle,” he says. “When the wheels on a bicycle are turning, it’s very easy to stay upright. Only if you have very, very good balance can you stay upright without the wheels turning. That’s the difference between real and synthetic inertia. It’s so much easier to stay upright if you are using the spinning mass of the wheels.”
Nobody runs a large-scale AC market without inertia, he says, and until those who claim batteries can provide the service can prove it, the reality is unknown. “No-one’s tried it at large scale.”
Until another couple of coal-fired power stations are retired and a few more gigawatts of large-scale renewables plants are built there is no incentive to go to large-scale storage, he says. “Except in South Australia, and only since the past 12 months, would it have been cost-effective to have large-scale pumped storage. Five or six years ago there was no arbitrage opportunity in the market at all. You would have lost money if you’d built a large battery.”
In Dargaville’s modelling 2030 is seen as the tipping point where storage will be sorely needed to stabilise the grid, as coal exits and renewables march ahead. The question at that point in time will be whether concentrated solar thermal is cheap enough to provide dispatchable clean energy. If it can’t, then pumped hydro looks good.
“But it doesn’t have to be one or the other,” he says. “You’re not going to build CSP in Tasmania, and there will be locations that are great for CSP but where you wouldn’t be able to build pumped hydro.”