A new study by energy experts from the Australian National University suggests that a 100 per cent renewable energy electricity grid – with 90 per cent of power coming from wind and solar – will be significantly cheaper future option than a coal or gas-fired network in Australia.
The study, led by Andrew Blakers, Bin Lu and Matthew Stocks, suggests that with most of Australia’s current fleet of coal generators due to retire before 2030, a mix of solar PV and wind energy, backed up by pumped hydro, will be the cheapest option for Australia, and this includes integration costs.
The report says that wind is currently about $64/MWh and solar $78/MWh, but the costs of both technologies are falling fast, with both expected to cost around $50/MWh when much of the needed capacity is built.
With the cost of balancing, this results in a levellised cost of energy (LCOE) of around $75/MWh.
By contrast, the LCOE of coal is $80/MWh, and some estimates – such as those by Bloomberg New Energy Finance which adds in factors such as the cost of finance risk – put it much higher.
Blakers says his team did not need to dial that higher price of coal into the equation: “We don’t include a risk premium or carbon pricing or fuel price escalation or threat of premature closure because renewables doesn’t need any of this to compete,” he says.
Nor do his estimates include any carbon price, which will further tip the balance in favour of renewables.
Nor do they include future cost reductions in wind and solar.
“There is no end in sight to cost reductions,” Blakers says.
“Much of Australia’s coal power stations will reach the end of their economic life over the next 15 years.
It will be cheaper to replace these with renewable energy.”
The two key outcomes of this modelling is that the additional cost of balancing renewable energy supply with demand on an hourly basis throughout the year is relatively small: $A25-$A30/MWh (US$19-23/MWh), and that means that the overall cost of a wind and solar dominated grid is much lower than previous estimates.
Indeed, the ANU team suggest that less storage is needed than thought.
The optimum amount of pumped hydro is 15-25 GW of power capacity with 15-30 hours of energy storage.
blakers 100This is based on more wind than solar.
If Hwind and PV annual energy generation is constrained to be similar then higher power (25 GW) and lower energy storage (12-21hours) is optimum.
Total storage of 450 GWh +/- 30% is optimum for all the scenarios. This is equivalent to the average electricity consumed in the NEM in 19 hours.
At this stage it should be pointed out that Blakers is a long time proponent of pumped hydro, and this modelling appears designed to support that technology.
For instance, the modelling avoids any “heroic” assumptions about technologies that have not been deployed at scale – meaning battery storage and solar thermal and storage are not included, and neither is geothermal or ocean energy.
Nor does the modelling – which looks at every hour of the year based on data from 2006-2010 – assume other opportunities such as demand management, when consumers agree and sometimes get paid for reducing their load at critical moments on the grid.
The modelling shows that a large fraction of the balancing costs relates to “periods of several successive days of overcast and windless weather that occur once every few years.”
Substantial reductions in balancing costs are possible through contractual load shedding (as occurred in Tomago aluminium smelter and BHP’s Olympic Dam recently), and the occasional use of legacy coal and gas generators to charge pumped hydro reservoirs if needed.
Another option is managing the charging times of batteries in electric cars.
“Although we have not modelled dynamical stability on a time scale of sub-seconds to minutes we note that pumped hydro) can provide excellent inertial energy, spinning reserve, rapid start, black start capability, voltage regulation and frequency control,” the authors write.
Pumped hydro has become a focus of attention in recent weeks, advocated by the Coalition government and others, seemingly in the absence of any consideration about the falling costs of battery storage.
EnergyAustralia last week announced a study into a large 100MW pumped hydro facility on South Australia’s Yorke Peninsular.
This work includes contributions from the ANU team.
So, how much does all this cost?
The ANU team estimates $184 billion, or $152 billion at future prices of wind and solar.
But before the Coalition and others start to hyperventilate about the billions to be spent, the ANU team also point out that this means no fuel costs in the future.
That’s why the key number is $75/MWh, which is around one third of the price that Queenslanders have been paying so far this year for their coal and gas power, making the investment in a 116MW solar farm by zinc producer Sun Metals, which is looking to expand its facility, as a good idea.
Some other interesting points from the study:
+ A sensitivity analysis has been performed on the baseline scenario by varying the following cost- components by +/- 25%: PV, wind, PHES, HVDC/HVAC, system lifetimes and discount rate.
The effect on LCOE is less than +/- $2/MWh except for system lifetimes, for which the effect is +/- $5/MWh, and wind capital cost and discount rate, for both of which the effect is +/- $10/MWh (about 10%).
+ Large scale deployment of electric vehicles and heat pumps would increase electricity demand by up to 40%.
Importantly these devices have large scale storage in the form of batteries in vehicles and heat/cool in water stores and the building fabric.
This storage may substantially reduce LCOB in the future.
+ The LCOB (levellised cost of balancing) calculated in this work is an upper bound.
A large fraction of LCOB relates to periods of several days of overcast and windless weather that occur once every few years.
Substantial reductions in LCOB are possible through reduced capital and maintenance costs, contractual load shedding, the occasional.
+ In most scenarios the modelling meets the NEM reliability standard of no more than 0.002% of unmet load (4 GWh per year) without demand management.”
However, in other scenarios we assume that demand management is employed during critical periods, which are typically cold wet windless weeks in winter that occur once every few years.
“During these periods the PHES reservoirs run down to zero over a few days because there is insufficient wind and PV generation to recharge them, leading to a shortfall in supply.
The amount of PV, wind and PHES storage could be increased to cover this shortfall. However, this substantial extra investment would be utilised only for a few days every few years.”
One suggestion is to relax the reliability standards: “A portion of the savings in investment in PV, wind and PHES would be available to compensate certain consumers for partial loss of supply for a few days every few years.
For example, reducing the overall cost of electricity supply by $2/MWh by allowing an unmet load of 336 GWh per 5 years would save $2 billion per 5 years, which is equivalent to $6,000 per unmet MWh.
Hmmm, but just imagine the headlines.
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