Australian coal exports to China plummeted last year. While this is due in part to recent trade tensions between Australia and China, our research suggests coal plant closures are a bigger threat to Australia’s export coal in the long term.
China unofficially banned Australian coal in mid-2020. Some 70 ships carrying Australian coal have reportedly been unable to unload in China since October.
This is obviously bad news for Australia’s coal exporters. But even if the ban is lifted, there’s no guarantee China will start buying Australian coal again – at least not in huge volumes.
China is changing. It’s announced a firm date to reach net-zero emissions, and governments in eastern provinces don’t want polluting coal plants taking up prime real estate. It’s time Australia faced reality, and reconsidered its coal export future.
In May last year, China’s government effectively banned the import of Australian coal, by applying stringent import quotas. As of last month coal exports to China from Newcastle, Australia’s busiest coal exporting port, had ceased.
In 2019, Australia exported A$13.7 billion worth of coal to China. This comprised A$9.7 billion in metallurgical coal for steel making and A$4 billion in thermal coal for electricity generation.
The latest official Australian data shows these export levels fell dramatically between November 2019 and November 2020. Comparing the two months, metallurgical and thermal coal exports to China were down 85% and 83% respectively.
Several Chinese provinces experienced power blackouts in late 2020. China’s state-backed media said the shortages were unrelated to the ban on Australian coal. Instead, they blamed cold weather and the recovery in industrial activity after the pandemic.
We dispute this claim. While Australian coal accounts for only about 2% of coal consumption in China, it helps maintain reliable supply for many power stations in China’s southeast coastal provinces.
Coal mining in China mostly occurs in the western provinces. Southeast coastal provinces are largely economically advanced and no longer produce coal. Instead, power stations in those provinces import coal from overseas.
Experience suggests trade tensions between Australia and China will eventually ease. But in the long run, there is a more fundamental threat to Australian coal exports to China.
Data from monitoring group Global Coal Tracker shows between 2015 and 2019, China closed 291 coal-fired power generation units in power plants of 30 megawatts (MW) or larger, totalling 37 gigawatts (GW) of capacity. For context, Australia decommissioned 5.5 GW of coal-fired power generation units between 2010 and 2017, and currently has 21 GW of coal-fired power stations.
The closures were driven by factors such as climate change and air pollution concern, excess coal power capacity, and China’s move away from some energy-intensive industries.
Our recently published paper revealed other distinctive features of the coal power station closures.
First, China’s regions are reducing coal power capacity at different rates and scales. In the nation’s eastern provinces, the closures are substantial. But elsewhere, and particularly in the western provinces, new coal plants are being built.
In fact, China’s coal power capacity increased by about 18% between 2015 and 2019. It currently has more than 1,000 GW of coal generation capacity – the largest in the world.
Second, we found retired coal power stations in China had much shorter lives than the international average. Guangdong, an economically developed region of comparable economic size to Canada, illustrates the point. According to our calculation, the stations in that region had a median age of 15 years at closure. In contrast, coal plants that closed in Australia between 2010 and 2017 had a median age of 43 years.
This suggests coal power stations in China are usually retired not because they’ve reached the end of their productive lives, but rather to achieve a particular purpose.
Third, our study showed decisions to decommission coal power stations in China were largely driven by government, especially local governments. This is in contrast to Australia, where the decision to close a plant is usually made by the company that owns it. And this decomissioning in China is usually driven by a development logic.
Coal plant closures there have been faster and bigger than elsewhere in the country, as governments replace energy- and pollution-intensive industries with advanced manufacturing and services.
And as these regions become richer, the value of land occupied by coal power plants and transmission facilities grows. This gives governments a strong incentive to close the plants and redevelop the sites.
In coming years, southeast China will increasingly shift to renewable-based electricity and electric power transmitted from western provinces.
Coal power stations in China’s eastern coastal regions will continue to close in coming years, and power generation capacity will be redistributed to western provinces. For reasons outlined above, that means power generation in China will increasingly rely on domestic coal rather than that from Australia.
China’s coal exit is in part due to its strategy to peak its carbon emissions before 2030 and achieve net-zero by 2060. Australia must realistically appraise its coal export prospects in light of the long-term threat posed by shifts in China and other East Asian nations.
The Morrison government, and industry, should re-double efforts to rapidly expand renewable energy in Australia. Then we can leave coal behind, and emerge as a renewable energy superpower.
Hao Tan, Associate professor, University of Newcastle; Elizabeth Thurbon, Scientia Associate Professor in International Relations / International Political Economy, UNSW; John Mathews, Professor Emeritus, Macquarie Business School, Macquarie University, and Sung-Young Kim, Senior Lecturer in International Relations, Discipline of Politics & International Relations, Macquarie School of Social Sciences, Macquarie University
2020 was a bumper year for solar power in Australia. More solar PV systems were installed in the first nine months than in all of any previous year.
Almost one in four Australian houses now have rooftop solar panels. But the number of solar panel incidents reported by fire and emergency services has increased too.
The exponential growth in solar PV and associated problems has attracted media and political attention.
In 2018, federal Energy Minister Angus Taylor warned his state counterparts lives were at risk from substandard solar panel installations. An audit of the Clean Energy Regulator by the Australian National Audit Office found there were potentially tens of thousands of badly installed and even unsafe rooftop systems. The regulator had inspected just 1.2% of rooftop installations.
State and territory regulators are responsible for electrical safety. Only Victoria mandates an inspection of each installed system.
Taylor announced an inquiry into the industry last August.
Last October, Fire and Rescue NSW Superintendent Graham Kingland said:
Over the last five years we have seen solar panel related fires increase five-fold. It is not uncommon to see solar panels cause house and building fires.
On Christmas day, ACT Fire & Rescue attended a fire at a home in Theodore where the solar panels caught alight. Coincidentally, the location was Christmas Street!
Last month, Energy Safe Victoria warned the public to get solar systems serviced.
Components such as DC isolators and inverters, rather than the actual panels, are the cause of most solar-related fires. A DC isolator is a manually operated switch next to a solar panel array that shuts off DC current between the array and the inverter. It was intended as an extra safety mechanism, but the switches have caused more problems than they have solved – particularly when not installed correctly or when poor-quality components are used.
A recent report rated Australia as one of the cheapest per kilowatt for solar PV, but it questioned our safety standards. Most solar systems sold in Australia use DC voltages that can pose a serious fire risk.
Unfortunately, Australia has been slow to adopt safer solar regulations. In contrast, the United States has had safety standards preventing the installation of conventional DC solar systems since as early as 2014.
It’s more difficult for lower-voltage, microinverter-based systems (requiring no DC isolator switch) to catch fire, but it’s not impossible.
An amendment to the DC isolator standard (AS/NZS 5033:2014) to improve product datasheets and ensure isolators can withstand the harsh Australian climate took effect on June 28 2019. By then, over 2 million systems had been installed on Australian rooftops.
Added to issues such as flammable cladding, dodgy electrical cable and other “grey imports” (products not sourced from approved manufacturers) in the building industry, we are now playing a game of catch-up.
Poor-quality solar rooftop components have led to an expanding list of product recalls. The latest Australian Competition and Consumer Commission (ACCC) recall list includes installations managed by industry giants such as Origin and AGL.
One notable recall in 2014 reported a risk of “arcing” and “eventual catastrophic failure, resulting in fire”. It listed no fewer than nine traders operating nationally as having used this failed product. The recall noted that the product supplier, Blueline Solar Pty Ltd, was insolvent.
What should consumers do? The ACCC said:
Owners should immediately shut down the PV system following the standard shutdown procedure.
If a consumer suspects they have one of the affected units, they should have an electrician inspect and replace the DC isolators.
Solar systems do not fall under the National Construction Code unless an ancillary structure is being created. Most systems are simply fixed with rails to an existing roof. If the code covered rooftop solar, this would require private certification and a compliance check on any system, as is the case overseas.
Research has shown consumers’ knowledge of solar systems is poor. Many owners have little idea if their system is working properly, or even at all.
And how would a consumer know what kind of DC isolator is on their roof or how to shut down the system in the event of a fire?
Solar panel systems are a growing incident category for firefighters. Yet even among firefighters there is some confusion on procedures to deal with a fire on live solar panels.
Solar panel fires have yet to make it onto a top 10 list of domestic fire causes (statistically, your Christmas tree lights are a greater risk). But the sheer volume of installations and ageing components in uninspected older systems are increasing the risks.
One Aussie inventor has developed a product PVStop — “a spray-on solution to mitigate solar panel risks by reducing DC output to safe levels to offer homeowners and emergency personnel peace of mind”.
The latest update on Clean Energy Regulator inspections completed to June 30 2020 shows a negligible 0.05% decrease in substandard systems. Roughly one in 30 systems (3.1%) have been deemed unsafe and another 17.9% substandard.
Without adequate solar PV industry standards, tools, inspection regimes, procedures or training, dangerous scenarios may increasingly put lives at risk. The high uptake of solar is very good news for reducing household electricity bills and carbon emissions, but safety issues undermine these positives.
The surge in installations, the introduction of batteries, the ageing of panels and components together with more extreme weather events mean solar panel incidents are likely to continue increasing.
Australia prides itself on being a world leader in household solar but until now we have not fully appreciated the safety risks. Fire authorities would do well to update fire safety guides that omit specific information on solar. And system owners should ensure they understand the risks and shut-down procedures.
With the cost of energy generated from wind and solar now less than coal, the share of Australia’s electricity coming from renewables has reached 23%. The federal government projects the share will reach 50% by 2030.
It is at this point that integrating renewables into the energy system becomes more costly.
We can add wind and solar farms at little extra cost when their share is low and other sources – such as coal and gas generators now – can compensate for their variability. At a certain point, however, there comes a need to invest in supporting infrastructure to ensure supply from mostly renewable generation can meet demand.
But by 2030, even with these extra costs, adding new variable renewable generation (solar and wind) to as high as a 90% share of the grid will still be cheaper than non-renewable options, according to new estimates from the CSIRO and Australian Energy Market Operator.
International research, including from the International Renewable Energy Agency, suggests solar and wind power are now the cheapest new sources of electricity in most parts of the world.
Our estimates, made for the third annual “GenCost” report (short for generation cost), confirm this is also now the case in Australia.
We compare the cost of new-build coal, gas, solar photovoltaics (both small and large scale), solar-thermal, wind and a number of speculative options (such as nuclear).
What we’ve been able to more accurately estimate in the new report is the cost of integrating more and more renewable energy into the energy system, as coal and gas generators are retired.
The two key extra integration costs are energy storage and more transmission lines.
For any system dominated by renewables, storing energy is essential.
Storage means renewable energy can be saved when it is overproducing relative to demand – for example, in the middle of the day for solar, or during extended windy conditions. Stored energy can then be used when renewables cannot meet demand – such as overcast days or at night for solar.
Among options being considered for large-scale investment in Australia are batteries and pumped hydro energy storage (using excess renewable power to pump water back up to dams to again drive hydroelectric turbines).
Pumped hydro sites can provide storage for hours or days. There are three schemes in Australia: Talbingo and Shoalhaven in New South Wales, and Wivenhoe near Brisbane.
Battery costs have been falling steadily and tend to be most competitive for storage electricity for less than eight hours. South Australia’s big battery (officially known as the Hornsdale Power Reserve) is the most obvious example.
The other key cost to integrate more renewable energy generation into the electricity grid is building more transmission lines. Right now those lines mostly run from coal and gas power stations near coal mines.
But this not where new large-scale renewable generation will be. Solar farms are best placed inland, where there is less cloud cover, and in the mid to northern regions of Australia. Wind farms are generally better located in elevated areas and in the southern regions. We’ll need to build new transmission links to these “renewable energy zones”.
Transmission links between the states in the National Electricity Market (Queensland, New South Wales, Australian Capital Territory, Victoria, Tasmania and South Australia) will need to be improved so they can better support each other if one or more are experiencing low renewable energy output.
So how much extra will it cost for Australia to have a higher share (up to 90%) of electricity from wind and solar (variable renewable energy)? The following graph summarises our findings based on 2030 cost projections.
The cost of generating energy from wind and solar (shown in light blue) is about A$40 per megawatt-hour (MWh). This is is slightly below current average market prices.
A higher share of renewable energy adds storage costs (in black) and transmission costs (grey and dark blue). These integration costs increase from A$4/MWh to A$20/MWh as the variable renewable energy share increases from 50% to 90%.
At 90% renewable energy, the total cost is A$63/MWh. But that’s still cheaper than the cost of new coal and gas-fired electricity generation, which is in the range of A$70 to A$90/MWh (under ideal assumptions of low fuel pricing and no climate policy risk).
The 2020-21 GenCost report is now in the formal consultation period with stakeholders including industry, government, regulators and academia. The final report is due to be published in March 2021.
Like so much of what I have done as Australia’s Chief Scientist, the electricity market review of 2017 was unexpected.
I was driving home after delivering a speech late one night in October 2016 when then federal energy minister Josh Frydenberg called and asked if I would chair a review of the National Electricity Market.
The urgent need had arisen as a consequence of the South Australian power blackout and ongoing concerns about the evolution of the electricity market. The call was brief; the task was huge.
This was new territory for me. While I have a PhD in electrical engineering, I had no specific interest in power systems. I had previously taken a business interest in green technologies. I had started a green lifestyle magazine, I had invested early in green technology stocks (and lost a small fortune), been involved in an electric car charging company, and I drove an electric car. I was an engineer but my work was in micro-electronics, at the scale of brain synapses. Large-scale power engineering had been my least favourite subject.
Now, it is close to my favourite. Work on low-emissions technologies has occupied a significant portion of my five-year term as Chief Scientist, which finishes at the end of this month.
Energy is a complex, vitally important topic, on which everyone has an opinion. The physics of human-induced global warming is irrefutable and a fast reduction in greenhouse gas emissions is urgent. Last summer’s bushfires were a grim reminder.
The Finkel Review at a glance
People often ask me whether climate policy is destined to destroy political leaders in Australia. Call me an optimist, but what I have seen is progress. When my proposed Clean Energy Target met its maker in October 2017, I was disappointed, but I was honestly excited the Australian, state and territory governments agreed to 49 out of 50 recommendations of our review.
Many of these recommendations ensured the electricity system would retain its operating strength as ever more solar and wind generation was added, and others ensured better planning processes for long-distance interconnectors and renewable energy zones. The public narrative that climate progress is moribund overlooks this ongoing work.
In early 2018, as I began to better understand the full potential of hydrogen in a low-emission future, I informally briefed Frydenberg, who responded by asking me to prepare a formal briefing paper for him and his state and territory counterparts. With support from government, industry, research and public interest colleagues, it developed last year into the National Hydrogen Strategy, which explored fully the state of hydrogen technology internationally and its potential for Australia.
The next step came this year with the Low Emissions Technology Statement, which articulates a solid pathway to tackle some of the pressing and difficult challenges en route to a clean economy. This was developed by Frydenberg’s successor, Angus Taylor, supported by advice from a panel I chaired.
When I was appointed Australia’s Chief Scientist in 2015, my predecessor Ian Chubb took me for a drink at Canberra’s Monster Bar. He had a prepared brief for me and we flicked through it. But Ian didn’t offer prescriptive advice, given the reality that the specifics of the role are defined by each chief scientist in line with requests from the government of the day.
I came to the role with a plan no more detailed than to work hard, do things well, be opportunistic, and always say yes – despite the device that sits on my desk and barks “no” whenever you hit the red button, a gift from my staff keen to see a more measured response to the many calls on my time.
I am most proud of my initiatives in STEM (science, technology, engineering and maths) education. These include the Australian Informed Choices project that ensures school students are given wise advice about core subjects that will set them in good stead for their careers; the STARPortal one-stop shop for information on extracurricular science activities for children; a report to the national education ministers on how businesses and schools can work together to provide context to science education; and the Storytime Pledge that acknowledges the fundamental importance of literacy by asking scientists to take a pledge to read to children.
But many of the high-profile tasks have arrived unexpectedly – the energy and low-emissions technology work, helping CSIRO with its report on climate and disaster resilience, and my work this year to help secure ICU ventilators and most recently, to review testing, contact tracing and outbreak management in the coronavirus pandemic.
The incoming Chief Scientist, Cathy Foley, will no doubt find, as I did, the job brings big surprises and unexpected turns. I expect she will also find government more receptive than ever to taking advice from experts in health, the physical sciences and the social sciences.
That doesn’t mean gratuitous advice. The advice we offer as scientists must be relevant and considered. Much of my advice has been in the form of deep-dive reviews, such as the report on national research facilities that was funded in the 2018 budget. But this year, amid the pandemic, we began something quite different: the Rapid Research Information Forum, which gives fast, succinct advice to government on very specific questions. This has been a highly effective way to synthesise the most recent research results with a very quick turnaround.
Nor does advice mean criticism. The Chief Scientist’s job is not to be the chief scientific critic of government policy. It is to advise ministers with the best that science has to offer. In turn, their job is to weigh that advice alongside inputs from other sectors and interests.
For me, working with the government has delivered results. Ministers have been receptive, have never told me what to say, and have agreed to the vast majority of my work being made public. In the energy sphere, we’ve made incredible progress. I am delighted to be staying on in an advisory role on low-emissions technologies.
When Frydenberg called late that evening in 2016, I had no idea where to begin to assess the state of the electricity market. And I had no idea that three years later we would be taking the first steps towards a clean hydrogen economy.
Now I am confident we will achieve the dramatic reduction in emissions that is necessary. Because of the immensity of the energy, industrial, agricultural and building systems, it will be slow and enormously difficult in a technical sense, politics aside.
Anyone who believes otherwise has not looked in detail at the production process for steel and aluminium. Converting these industries to green production is a mammoth task. But the political will is there. Industry is on the job, as is the scientific community, and the work has started.
The beginning of my term coincided with one of the most momentous scientific breakthroughs in a century: the detection of gravitational waves, literally ripples in the fabric of spacetime. This confirmed a prediction made by Einstein 100 years ago and was the final piece in the puzzle of his Theory of General Relativity.
As I finish my term, the contribution of Australian scientists to that discovery has just been recognised in the Prime Minister’s Prizes for Science. As chair of the Prizes selection committee, this was a nice bookend for me. More importantly, it’s a reminder we are playing the long game.
Several Australian states are going it alone on the the energy transition. The policies adopted by New South Wales, Victoria, Queensland and others represent major departures from the existing national approach, and run counter to the neoliberal principles underpinning the current system.
Most notably, the NSW Coalition government announced its electricity infrastructure roadmap. The government says by 2030, the policy will enable A$32 billion in private sector investment, and bring 12 gigawatts of new renewable energy capacity online. This is roughly equivalent to the amount of large-scale wind and solar installed in the National Electricity Market to date.
The states were forced to act on renewables after the federal government effectively vacated the policy space. The NSW law has been widely hailed as a victory for the clean energy transition, but also represents a return to the centrally planned system of decades past. In fact, it may well signal the breakup of the National Electricity Market as we know it today.
This presents risks and challenges which, if not managed carefully, may result in white elephants and higher electricity bills for consumers.
Before the 1990s, electricity supply was fundamentally understood as a state responsibility. State-owned companies were tasked with generating, distributing and supplying electricity.
But in the 1990s, things changed, for several reasons. First, the cost of electricity supply was rising at a concerning rate. Second, neoliberalism began to dominate economic reform in Australia and internationally. Governments saw their jobs less as providing services (such as electricity), and more as promoting markets and competition to make systems, such as electricity supply, more efficient.
Also in the 1990s, two key inquiries – the Productivity Commission’s report into energy generation and distribution, and the Hilmer inquiry into national competition policy – identified issues in the electricity industry. These included wasteful overinvestment, largely driven by the political imperatives of keeping the lights on at all costs, and creating jobs in specific locations and electorates.
A new, reformed system, the National Electricity Market, began operating in 1998. It included all states and territories except Western Australia and the Northern Territory. In this new system, market logic – rather than central planners and bureaucrats – would decide the the location, timing and type of new energy generation investment. Private firms would supply electricity to consumers using price signals and contract markets to guide decisions.
Key to this new system was a set of highly prescriptive rules, and a process to develop them. This culminated in the Australian Energy Market Agreement and the establishment of three national energy market institutions we have today:
This market structure, and strict separation of powers and functions, was partly to isolate policy and investments from the political whims of the day.
The NSW government legislation is the latest, and perhaps most significant, in a string of policies to reject the old national market approach. Grattan Institute energy director Tony Wood described it as “the most extreme intervention we have seen to date, and moves even more closely to a centrally planned energy system and away from a market approach, than anything else I have seen to date”.
NSW is not alone here. In Victoria, the Andrews government is building the Southern Hemisphere’s biggest battery at Geelong, under a new law that sits outside the national framework. And government this month also announced a A$550 million budget plan to create six renewable energy hubs, and also bring another 600 megawatts of renewable energy generation online.
Such interventions are not limited to the states. The federal government is building the Snowy 2.0 pumped hydro scheme. It has threatened to build a 1,000MW gas generator, and has established a scheme to underwrite energy investments. And the Energy Security Board has the power to make rules outside the regular process, which it used most recently to tighten the standards around energy reliability.
The breakdown can largely be sheeted home to one factor: a lack of climate policy at a national level. This has left the states with little option than to manage the energy transition, and climate action, on their own.
The NSW policy will undoubtedly affect projects already in the pipeline. Following the announcement, both AGL and Energy Australia put the brakes on battery and gas projects in the state.
And the Australian Energy Council, which represents major electricity retailers, expressed “concern about its impact on the functioning of an increasingly interconnected National Electricity Market and the complexity it will certainly add to investment decisions”.
It’s hard to argue against a democratically elected state government pursuing what is within its constitutional remit – particularly given the federal failure on climate policy. But existing institutions and frameworks are not equipped to govern that kind of system.
So if the states do continue to go it alone, we need a new national accord which clarifies the roles and responsibilities of each government. That would ensure we don’t repeat mistakes of the past, and in particular excessive over investment for which consumers foot the bill.
Biomethane technology is no longer on the backburner in Australia after an announcement this week that gas from Sydney’s Malabar wastewater plant will be used to power up to 24,000 homes.
Biomethane, also known as renewable natural gas, is produced when bacteria break down organic material such as human waste.
The demonstration project is the first of its kind in Australia. But many may soon follow: New South Wales’ gas pipelines are reportedly close to more than 30,000 terajoules (TJs) of potential biogas, enough to supply 1.4 million homes.
Critics say the project will do little to dent Australia’s greenhouse emissions. But if deployed at scale, gas captured from wastewater can help decarbonise our gas grid and bolster energy supplies. The trial represents the chance to demonstrate an internationally proven technology on Australian soil.
Biomethane is a clean form of biogas. Biogas is about 60% methane and 40% carbon dioxide (CO₂) and other contaminants. Turning biogas into biomethane requires technology that scrubs out the contaminants – a process called upgrading.
The resulting biomethane is 98% methane. While methane produces CO₂ when burned at the point of use, biomethane is considered “zero emissions” – it does not add to greenhouse gas emissions. This is because:
it captures methane produced from anaerobic digestion, in which microorganisms break down organic material. This methane would otherwise have been released to the atmosphere
it is used in place of fossil fuels, displacing those CO₂ emissions.
Biomethane can also produce negative emissions if the CO₂ produced from upgrading it is used in other processes, such as industry and manufacturing.
Biomethane is indistinguishable from natural gas, so can be used in existing gas infrastructure.
The Malabar project, in southeast Sydney, is a joint venture between gas infrastructure giant Jemena and utility company Sydney Water. The A$13.8 million trial is partly funded by the federal government’s Australian Renewable Energy Agency (ARENA).
Sydney Water, which runs the Malabar wastewater plant, will install gas-purifying equipment at the site. Biogas produced from sewage sludge will be cleaned and upgraded – removing contaminants such as CO₂ – then injected into Jemena’s gas pipelines.
Sydney Water will initially supply 95TJ of biomethane a year from early 2022, equivalent to the gas demand of about 13,300 homes. Production is expected to scale up to 200TJ a year.
A report by the International Energy Agency earlier this year said biogas and biomethane could cover 20% of global natural gas demand while reducing greenhouse emissions.
As well as creating zero-emissions energy from wastewater, biomethane can be produced from waste created by agriculture and food production, and from methane released at landfill sites.
The industry is a potential economic opportunity for regional areas, and would generate skilled jobs in planning, engineering, operating and maintenance of biogas and biomethane plants.
Methane emitted from organic waste at facilities such as Malabar is 28 times more potent than CO₂. So using it to replace fossil-fuel natural gas is a win for the environment.
It’s also a win for Jemena, and all energy users. Many of Jemena’s gas customers, such as the City of Sydney, want to decarbonise their existing energy supplies. Some say they will stop using gas if renewable alternatives are not found. Jemena calculates losing these customers would lose it A$2.1 million each year by 2050, and ultimately, lead to higher costs for remaining customers.
The challenge for Australia will be the large scale roll out of biomethane. Historically, this phase has been a costly exercise for renewable technologies entering the market.
Worldwide, the top biomethane-producers include Germany, the United Kingdom, Sweden, France and the United States.
The international market for biomethane is growing. Global clean energy policies, such as the European Green Deal, will help create extra demand for biomethane. The largest opportunities lie in the Asia-Pacific region, where natural gas consumption and imports have grown rapidly in recent years.
Australia is lagging behind the rest of the world on biomethane use. But more broadly, it does have a biogas sector, comprising than 240 plants associated with landfill gas power units and wastewater treatment.
In Australia, biogas is already used to produce electricity and heat. The step to grid injection is sensible, given the logistics of injecting biomethane into existing gas infrastructure works well overseas. But the industry needs government support.
Last year, a landmark report into biogas opportunities for Australia put potential production at 103 terawatt hours. This is equivalent to almost 9% of Australia’s total energy consumption, and comparable to current biogas production in Germany.
While the scale of the Malabar project will only reduce emissions in a small way initially, the trial will bring renewable gas into the Australia’s renewable energy family. Industry group Bioenergy Australia is now working to ensure gas standards and specifications are understood, to safeguard its smooth and safe introduction into the energy mix.
The Morrison government has been spruiking a gas-led recovery from the COVID-19 recession, which it says would make energy more affordable for families and businesses and support jobs. Using greenhouse gases produced by wastewater in Australia’s biggest city is an important – and green – first step.
When it comes to handling the waste crisis in Australia, options are limited: we either export our waste or bury it. But to achieve current national targets, policy-makers are increasingly asking if we can instead safely burn waste as fuel.
Proposals for waste incinerators are being considered in the Greater Sydney region, but these have been lambasted by the Greens and independent members of the NSW parliament, who cite public health concerns.
Meanwhile, the ACT government has recently put a blanket ban on these facilities.
But are their concerns based on evidence? In our systematic review of the scientific literature, we could identify only 19 papers among 269 relevant studies — less than 10% — that could help address our question on whether waste-to-energy incinerators could harm our health.
This means the answer remains unclear, and we therefore call for a cautious approach to waste-to-energy technology.
On average, Australia produces roughly 500 kilograms of municipal (residential and commercial) waste each year. This aligns with the OECD average.
New Zealand in comparison, despite its strong environmental stance, is among the worst offenders for producing waste in any OECD country. It produces almost 800 kilograms per person per year.
Now, most recyclable or reusable waste in Australia goes to landfill. This poses a potential risk to both climate and health with the emission of potent greenhouse gases such as methane and the leaching of heavy metals such as lead into the groundwater. As a result, local governments may want to seek alternative options.
“Waste-to-energy” incineration is when solid waste is sorted and burned as “refuse-derived” fuel to generate electricity. This can replace fossil fuel such as coal.
Every day, around 300 trucks filled with non-recyclable municipal solid waste are sent to Amager Bakke.
This fuels a furnace that runs at 1,000℃, turning water into steam. And this steam provides electricity and heat to around 100,000 households. Generally, people in Denmark warmly welcome it.
In Australia and the US, community reception towards the building of new incinerators has been cold.
The big concern is burning waste may release chemicals that can harm our health, such as nitrogen oxide and dioxin. Exposure to high levels of dioxin can lead to skin lesions, an impaired immune system and reproductive issues.
However, control measures, such as the technologically advanced filters used in Amager Bakke, can bring the amount of dioxin released to near zero.
Supply of this plastic could come from the waning fossil fuel industry. This would work against the goal of establishing a “circular economy” that reuses and recycles goods where possible.
An analysis from 2019 found that to meet European Union circular economy goals, Nordic countries would need to increase their recycling, and significantly shift away from incineration.
This concern is understandable given incinerators operate cleanest when fuelled at full capacity. This is because a higher temperature means a more complete combustion — a bit like less ash and smoke coming off of a well-built campfire.
As with many policy solutions, determining the safety of burning waste is complicated.
Our review found a lack of evidence to fully reject well-designed and operated facilities. However, based on the limited number of health studies we found, we support a precautionary planning approach to waste-to-energy proposals.
This means we need appropriate health risk assessment and life cycle analyses built into the approval process for each and every incinerator proposed in the near-future.
The studies we found were all performed in the last 20 years. None were from the Nordic countries, however, where waste-to-energy incineration has been in use for many decades.
The reasons for the Nordic embrace of this technology are speculative. One reason may be that their level of economic development allows large capital investment for safe, state-of-the-art design and operation.
If councils are determined to pursue waste-to-energy incineration, we suggest they prioritise specific applications.
For example, we found the process with the most favourable life-cycle assessment (the most beneficial to health compared to traditional fossil fuel use) was the “co-incineration” of refuse-derived fuel for industrial cement.
Currently, cement kilns are mostly fuelled by burning coal, and it’s difficult to reach the high temperatures required with traditional renewables. This means substituting coal for refuse-derived fuel could reduce the industry’s dependency on coal, when renewables aren’t an option.
So, while we wait for more knowledge on how waste-to-energy incineration may affect our health, let’s focus on improving our waste hierarchy, rather than exporting our waste to feed a global crisis.
Thomas Cole-Hunter, Research fellow, Queensland University of Technology; Ana Porta Cubas, Knowledge and Translation Broker- Centre for Air pollution, energy and health Research (CAR), University of Sydney; Christina Magill, Senior Natural Hazards Risk Scientist, GNS Science, and Christine Cowie, Senior Research Fellow, Centre for Air Quality & Health Research and Evaluation, Woolcock Institute of Medical Research, University of Sydney; Senior Research Fellow, South West Sydney Clinical School, UNSW
It’s now beyond dispute that — for new electricity generation — solar, wind and other forms of renewable energy are cheaper than anything else: cheaper than new coal fired power stations, cheaper than new gas-fired stations and cheaper than new nuclear power plants.
The International Energy Association says so. Its latest World Energy Outlook describes solar as the cheapest electricity in history.
Solar costs 20% to 50% less than it thought it would two years ago.
Attention has turned instead to the ways to best meet demand when renewable resources are not available.
The government is a big supporter of gas, and as importantly, pumped hydro.
Pumped hydro is an old technology, as old as the electricity industry itself.
It became fashionable from the 1960s to 1980s as a complement to inflexible coal and nuclear generators.
When their output wasn’t needed (mainly at night) it was used to pump water to higher ground so that it could be released and used to run hydro generators when demand was high.
Australia’s three pumped hydro plants are old, built at least 40 years ago, and they operate infrequently, and sometimes not at all for years.
Gas fired electricity generation, whether by turbines (essentially a bigger version of those found on aeroplanes) or by conventional reciprocating engines, has several advantages over pumped hydro including much smaller local environmental impacts and in many cases smaller greenhouse gas impacts.
They can be built quickly and, most importantly, if there is a gas supply they can be built close to electrical loads. There are 17 gas-fired peaking generators in the National Electricity Market, but none have been built over the past decade.
Batteries have advantages over both.
In 2017, Australia built the world’s biggest battery, but it since been overtaken by a Californian battery more than twice its size and may soon be overtaken by one 150 times the size as part of the Sun Cable project in the Northern Territory which will send solar and stored electricity to Singapore.
In a study commissioned by the Bob Brown Foundation, we have compared the pumped hydro “battery of the nation” project to actual batteries and to gas turbines.
The battery of the nation (BoTN) is a proposal instigated by the Australian and Tasmanian governments to add more pumped hydro to Tasmania’s hydro power system and used enhanced interconnectors to provide electricity on demand to Victoria.
We sought to determine what could most cost-effectively provide Victoria with 1,500 megawatts — the BoTN, gas turbines or batteries.
Partly this depends on how long peak demand for dispatchable power last. BoTN would be able to provide sustained power for 12 hours, but we found that in practice, even when our system becomes much more reliant on renewables, it would be unusual for anything longer than four hours to be needed.
We could easily dismiss gas turbines — the Australian Energy Market Operator’s costings have batteries much cheaper than gas turbines to build and operate now and cheaper still by the time the Battery of the Nation would be built.
And batteries are able to respond to instructions in fractions of a second, making them useful in ways gas and pumped hydro aren’t.
They are also able to be placed where they are needed, rather than where there’s a gas connection or an abandoned mine, cliff or hill big enough to be used for pumped hydro.
We found batteries could supply 1,500 megawatts of instantly-available power for less than half of the cost of the enhanced Tasmania to Victoria cable alone, meaning that even if the rest of the BoTN cost little, batteries would still be cheaper.
Origin Energy recently gave up on expanding the Shoalhaven pumped hydro scheme in NSW after finding it would cost more than twice as much to build as first thought.
Similarly, investor-owned Genex has repeatedly deferred its final investment decision on one of the cheapest pumped hydro options in Australia — using depleted gold mine pits in Queensland — despite being offered concessional loans from the Australian Government to cover the entire build cost.
The final barrier seems to be obtaining subsidies from the Queensland Government to fund the necessary transmission lines.
Snowy 2.0 seems to be proceeding after the Australian Government pumped in $1.4 billion to get it going, and paid a king’s ransom to New South Wales and Victoria for their shares in Snowy Hydro.
Yet even before the main works are to start, credit rating agency S&P has down-graded Snowy Hydro’s stand-alone debt to “junk” and suggested the government will need to pump more money into Snowy Hydro to protect its debt.
Prime Minister Morrison has said recently that batteries can’t compete with gas generators , yet a couple of days later, his government announced support for a 100 megawatt battery in Western Australia, where gas is less than half the price it is on the east coast.
Our analysis suggests neither gas nor pumped hydro can compete with batteries, and if the prime minister wants more of either, he will have to dip his hands deeply into tax payer’s pockets to get it.
The proposed Asian Renewable Energy Hub (AREH) will be a huge step forward. It would eventually comprise 26,000 megawatts (MW) of wind and solar energy, generated in Western Australia’s Pilbara region. Once complete, it would be Australia’s biggest renewable energy development, and potentially the largest of its type in the world.
Late last week, the federal government granted AREH “major project” status, meaning it will be fast-tracked through the approvals process. And in another significant step, the WA government this month gave environmental approval for the project’s first stage.
The mega-venture still faces sizeable challenges. But it promises to be a game-changer for Australia’s lucrative energy export business and will reshape the local renewables sector.
Australia’s coal and gas exports have been growing for decades, and in 2019-20 reached almost A$110 billion. Much of this energy has fuelled Asia’s rapid growth. However, in recent weeks, two of Australia’s largest Asian energy markets announced big moves away from fossil fuels.
China adopted a target of net-zero greenhouse emissions by 2060. Japan will retire its fleet of old coal-fired generation by 2030, and will introduce legally binding targets to reach net-zero emissions by 2050.
The Asian Renewable Energy Hub (AREH) would be built across 6,500 square kilometres in the East Pilbara. The first stage involves a 10,000MW wind farm plus 5,000MW of solar generation – which the federal government says would make it the world’s largest wind and solar electricity plant.
The first stage would be capable of generating 100 terawatt-hours of renewable electricity each year. That equates to about 40% of Australia’s total electricity generation in 2019. AREH recently expanded its longer term plans to 26,000MW.
The project is backed by a consortium of global renewables developers. Most energy from AREH will be used to produce green hydrogen and ammonia to be used both domestically, and for shipping to export markets. Some energy from AREH will also be exported as electricity, carried by an undersea electrical cable.
Another Australian project is also seeking to export renewable power to Asia. The 10-gigawatt Sun Cable project, backed by tech entrepreneur Mike Cannon-Brookes, involves a solar farm across 15,000 hectares near Tennant Creek, in the Northern Territory. Power generated will supply Darwin and be exported to Singapore via a 3,800km electrical cable along the sea floor.
The export markets for both AREH and Sun Cable are there. For example, both South Korea and Japan have indicated strong interest in Australia’s green hydrogen to decarbonise their economies and secure energy supplies.
But we should not underestimate the obstacles standing in the way of the projects. Both will require massive investment. Sun Cable, for example, will cost an estimated A$20 billion to build. The Asian Renewable Energy Hub will reportedly require as much as A$50 billion.
The projects are also at the cutting edge of technology, in terms of the assembly of the solar array, the wind turbines and batteries. Transport of hydrogen by ship is still at the pilot stage, and commercially unproven. And the projects must navigate complex approvals and regulatory processes, in both Australia and Asia.
But the projects have good strategic leadership, and a clear mission to put Australian green energy exports on the map.
Together, the AREH and Sun Cable projects do not yet make a trend. But they clearly indicate a shift in mindset on the part of investors.
The projects promise enormous clean development opportunities for Australia’s north, and will create thousands of jobs in Australia – especially in high-tech manufacturing. As we look to rebuild the economy after the COVID-19 pandemic, such stimulus will be key. All up, AREH is expected to support more than 20,000 jobs during a decade of construction, and 3,000 jobs when fully operating.
To make smart policies and investments, the federal government must have a clear view of the future global economy. Patterns of energy consumption in Asia are shifting away from fossil fuels, and Australia’s exports must move with them.
John Mathews, Professor Emeritus, Macquarie Business School, Macquarie University; Elizabeth Thurbon, Scientia Associate Professor in International Relations / International Political Economy, UNSW; Hao Tan, Associate professor, University of Newcastle, and Sung-Young Kim, Senior Lecturer in International Relations, Discipline of Politics & International Relations, Macquarie School of Social Sciences, Macquarie University