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Australia's outages make the resiliency case for solar and batteries

When fierce February weather toppled transmission towers, distributed resources were key to averting widespread failures.

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Photo credit: Kyle Dillehay / Department of Energy

Photo credit: Kyle Dillehay / Department of Energy

It was the second unprecedented transmission failure in less than a decade. 

On February 13, more than 500,000 homes and businesses in the state of Victoria, Australia lost power. Some were left in the hot dark for days, during summer’s peak. Others waited weeks. 

At root, it was a classic case of extreme weather compromising the grid — with high winds wreaking havoc on poles and wires. But that didn’t stop a politicized blame game from playing out. 

Those on the left blamed the privatization of transmission and distribution infrastructure and aging coal generators as having caused the blackout, while conservatives instead blamed the large and growing share of renewables on the grid. Neither narrative, though, cut to the bone of the issue: the vulnerability of transmission itself, particularly as the weather worsens. 

“It doesn’t matter what generation is at the end of the transmission line: if the transmission line gets knocked over it can’t connect,” said David Dixon, a Sydney-based renewables analyst at Rystad Energy. 

The Australian Electricity Market Operator, or AEMO, moved quickly to investigate the blackout, publishing a preliminary report only two days later. It found that the Feb. 13 outages occurred when 75-mph winds gusted in ahead of an intense storm front, right as a period of extreme heat began to break. Six transmission towers collapsed — literally folded in two — bringing conductive wires crashing to the ground and tripping two 500-kilovolt transmission lines. 

With the lines down, a series of traditional and renewable generators disconnected from the network, resulting in a temporary shortage in supply, right when and where it was needed. Downed trees and damage to the distribution network only made things worse. 

In total, AEMO found that 2.69 gigawatts of generation was lost during the event, requiring network operators to “shake off” 1,000 MW of load to maintain system stability, and utilities to shed 300 MW of load in the metropolitan area, which they did by cutting power supply to some homes and businesses. Spot market electricity prices hit a regulated cap of approximately $10,100 (or AU$16,600) per megawatt-hour. 

“There was enough generation in the Victoria region to meet demand. However, due to constraints on the network, this generation was not able to supply the load,” concluded AEMO in its preliminary report. 

Crucially, while electricity system operators shed some of the necessary load, the measures taken by AEMO were sufficient to maintain system stability in the face of wild weather. The operator drew on undersea and overhead connectors to the neighboring states of Tasmania, New South Wales, and South Australia to regulate grid frequencies and supply power. And with major coal generators offline, the 2.3 GW of rooftop solar distributed throughout the network became the state’s largest source of generation. 

The storm, and its aftermath, resulted in an unanticipated case study in how distributed and flexible resources can assist in averting widespread failure in the face of intense pressure on the power system. 

Photo credit: Kyle Dillehay / Department of Energy

Déjà vu?

There was something eerily familiar about the events of Feb 13. 

On Sept. 28, 2016, freakish winds toppled interstate transmission towers linking South Australia to Victoria. The state, which had said farewell to its last coal generator in May of that year, became “islanded” and a series of cascading system failures caused a state-wide blackout impacting over 850,000 customers. 

The resulting furor saw vehement debate grip both the state and national discourse. After wind generators in South Australia in 2016 failed to “ride through” the grid disturbance, renewable energy more generally was castigated as being unreliable energy — and the reputational damage was lasting.

While the debate that emerged this year in the wake of Feb. 13 involved some of these same talking points, there was a marked change: the discussion seemed to recognize the value of the many solar and energy storage assets that have been distributed throughout the network in the more than seven years since the 2016 crisis. In terms of stability, rooftop PV was spoken of as a feature rather than a bug. 

“If there is a generator at one end, and the city at another, and the transmission goes down, you lose that generation,” said Dixon. “The beauty of distributed resources in the cities is that you have them right next to the load — you effectively lose a lot of that transmission risk.”

Energy market experts echoed this sentiment. Roger Dargaville, the director of the Monash Energy Institute, wrote in The Conversation only one day after the outage that “one benefit of renewable energy systems is that they tend to be much more widely ‘distributed’ geographically than coal generators. So when power lines go out, having a more distributed network actually provides more resilience.”

Batteries also played a part: “Batteries have ultra-rapid responses to these kinds of disruptions,” he added, “and can add or subtract power from the grid within milliseconds to keep the grid stable.”

Photo credit: Kyle Dillehay / Department of Energy

Shape of things to come

Both the rapid pace and fundamental nature of the changes to Australia’s electricity system over the past decade have been remarkable.  

Utility-scale batteries in particular are proliferating dramatically. Rystad Energy tracks roughly 3.5 GW of big batteries currently under construction in the country, in addition to the 1.5 GW already energized and in operation.

Residential energy storage remains at smaller volumes but is becoming more common. Slightly more than 20% of residential solar systems sold in Australia in 2023 were installed alongside batteries, according to BloombergNEF. While that pales in comparison to the nearly 80% installed in Germany and 70% in Italy in the same year, it is beginning to build to meaningful volumes. 

Rooftop solar itself remains enormously popular in Australia. Over one-third of Australian households, or 3.36 million homes, had a rooftop PV system in 2022, according to the International Energy Agency. And installation rates continue to remain robust despite the highly saturated market. According to Green Energy Markets, residential and small-commercial solar installations approached 3.15 GW in 2023, only slightly behind the record setting year 2021, in which 3.2 GW was installed.  

Penetration levels in newer suburbs on the outskirts of the capital cities — where the decision to add solar to a new-build home is a relatively simple one — is already at over 50%, the IEA found. These suburbs are demonstrating that the distribution network can handle far higher penetration levels of PV than previously thought.

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The beauty of distributed resources in the cities is that you have them right next to the load — you effectively lose a lot of that transmission risk.
David Dixon, Sydney-based renewables analyst at Rystad Energy

Tristan Edis, director of analysis for Green Energy Markets, observed in a paper forecasting staggering levels of rooftop PV penetration that more than 5 million Australians already live in suburbs where every second home has rooftop PV. 

“A lot of things are combining to allow network operators to gain more understanding about and become more comfortable with really high amounts of PV on their networks,” Edis told Latitude Media, adding that developments including smart meter roll-outs, reforms that give operators remote access to solar inverters, and “dynamic export” requirements have together given operators confidence in managing the expanding rooftop solar fleet. 

Going forward, there is growing acceptance that Australian rooftop solar will be a runaway train. Recent scenarios from Green Energy Markets forecasted that between 66 GW and 98 GW of residential solar will be installed through to 2050 in Australia — far beyond the current 41 GW of all electricity generation capacity in operation today. 

Distributed incentive, and network innovation

The cost-benefit analysis conducted after Project EDGE found billions in savings for the electricity system through VPP deployment. (Source: AEMO)

Economics also plays an important role. In 2021, regulations were changed to allow network operators to charge for solar exports — particularly at times of peak PV output. And it appears that the change has influenced how those operators think about solar. 

“Distribution companies are now more constructive as they can charge for solar exports — the ‘solar tax,’” said Edis. “What that has meant is that the distribution companies can make money from integrating more rooftop solar PV. Voltage rise is the [technical] problem, but it is very manageable.”

Four publicly funded trials have assessed the efficacy of large amounts of distributed solar and storage under various conditions and applications. 

The first to report was Project EDGE, or the Energy Demand and Generation Exchange, in Victoria. In what was essentially a one-year virtual power plant evaluation pilot, it found that a VPP that aggregated solar and storage in the state could deliver savings of almost $4 billion (AU$6 billion) via the provision of grid services and the shaving of peak demand. The project involved the network operator, AEMO, a prosumer aggregator, and a grants agency. 

Importantly, EDGE found that while there was interest in VPPs from households, securing buy-in from consumers was vital. And addressing data security concerns will also prove important going forward. 

Bruce Mountain, the director of the Victoria Energy Policy Center, said that there’s “a spirit of innovation” in the world of DERs right now.

“All the VPPs and the software: it’s the sexy space to be and it's where the innovative managers and engineers want to be,” he said, adding that while there may have been antipathy towards rooftop solar among network operators in the past, this appears to have subsided.

Mountain said that distribution network operators in places like South Australia and Victoria have added new digital monitoring and control capabilities to assets, providing them with the ability to analyze and control network behavior in new ways.

“They've come up with schemes to vary the network capability based on aggregate PV exports on parts of the network, and built the control systems to be able to centrally vary the settings on distribution transformers,” he said. “They've done a whole lot of these smart things, and when I went to go and visit them, they were very chuffed that they've been able to do this.”

While these early signs are encouraging to stakeholders, progress in both the mindset and the technical capabilities of network operators remains essential — especially as extreme weather becomes the norm

An independent review has been ordered into the Feb. 13 outages by the state government, from which Mountain said the role of transmission has been “explicitly omitted” by the government, much to his chagrin.

Even as distributed generation like rooftop solar transforms the electricity network, as Dixon said, “if there is no transmission line, there is no supply.”

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