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Australia electricity grid transition is accelerating as renewables, wind, solar, and storage drive decentralised generation, emissions cuts, and NEM trade shifts, with South Australia becoming a net exporter post-Hazelwood closure and rooftop solar surging.

Key Points

Australia electricity shift to renewables, distributed generation and storage, cutting emissions, reshaping NEM flows.

✅ South Australia now exports power post-Hazelwood closure

✅ Rooftop solar is the fastest-growing NEM generation source

✅ Gas peaking and storage investments balance variable renewables

The politics may not change much, but Australia’s electricity grid is changing before our very eyes – slowly and inevitably becoming more renewable, more decentralised, and in step with Australia's energy transition that is challenging the pre-conceptions of many in the industry.

The latest national emissions audit from The Australia Institute, which includes an update on key electricity trends in the national electricity market, notes some interesting developments over the last three months.

The most surprising of those developments may be the South Australia achievement, which shows that since the closure of the Hazelwood brown coal generator in Victoria in March 2017, and as renewables outpacing brown coal in other markets, South Australia has become a net exporter of electricity, in net annualised terms.

Hugh Saddler, lead author of the study, notes that this is a big change for South Australia, which in 1999 and 2000, when it had only gas and local coal, used to import 30% of its electricity demand.

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The fact that wholesale prices in South Australia were higher in other states – then, as they are now – has nothing to with wind and solar, but the fact that it has no low-cost conventional source and a peaky demand profile (then and now).

“The difference today is that the state is now taking advantage of its abundant resources of wind and solar radiation, and the new technologies which have made them the lowest cost sources of new generation, to supply much of its electricity requirements,” Saddler writes.

Other things to note about the flows between states is that Victoria was about equal on imports and exports with its three neighbouring states, despite the closure of Hazelwood. NSW continues to import around 10% of its needs from cheaper providers in Queensland.

Gas-fired generation had increased in the last year or two in South Australia as a result of the Northern closure, but is still below the levels of a decade ago.

But because it is expensive, this is likely to spur more investment in storage.

As for rooftop solar, Saddler notes that the share of residential solar in the grid is still relatively small but, despite excess solar risks flagged by distributors, it is the most steadily growing generation source in the NEM.

That line is expected to grow steadily. By 2040, or perhaps 2050, the share of distributed generation, which includes rooftop solar, battery storage and demand management, is expected to reach nearly half of all Australia’s grid demand.

Saddler, says, however, that the increase in large-scale solar over the last few months is a significant milestone in Australia’s transition towards clean electricity generation, mirroring trends in India's on-grid solar development seen in recent years. (See very top graph).

“Firstly, they are a concrete demonstration that the construction cost advantage, which wind enjoyed over solar until a year or two ago, is gone.

“From now on we can expect new capacity to be a mix of both technologies. Indeed, the Clean Energy Regulator states that it expects solar to account for half of all (new renewable) capacity by 2020, and the US is moving toward 30% from wind and solar as well.”

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Enbridge Alberta CCS Project targets carbon capture and storage in Alberta, capturing emissions from industrial emitters to advance net-zero goals, leveraging carbon pricing, regulatory support, and a hub model despite a key partner's exit.

Key Points

A proposed Alberta carbon capture hub by Enbridge to store industrial emissions and support net-zero targets.

✅ Seeks emitters across power, oil and gas, and heavy industry

✅ Backed by carbon pricing, regulation, and net-zero mandates

✅ Faces high capex, storage risk, and anchor-tenant uncertainty

Enbridge Inc., a Canadian energy giant, is digging its heels in on its proposed carbon capture and storage (CCS) project in Alberta. This comes despite the recent withdrawal of Capital Power, a major potential emitter that was expected to utilize the CCS technology. Enbridge maintains the project remains viable, but questions linger about its future viability without a cornerstone anchor.

The CCS project, envisioned as a major carbon capture hub in Alberta, aimed to capture emissions from industrial facilities and permanently store them underground. This technology has the potential to play a significant role in reducing greenhouse gas emissions and mitigating the effects of climate change, alongside grid solutions like bridging the Alberta-B.C. electricity gap that can complement decarbonization efforts.

Capital Power's decision to shelve its $2.4 billion Genesee Generating Station project, which was designed to integrate with the CCS hub, threw a wrench into Enbridge's plans. The Genesee project was expected to be a key source of emissions for capture and storage, and its status is being weighed as Ottawa advances the federal coal plan to phase out unabated coal.

Enbridge, however, remains optimistic. The company cites ongoing discussions with other potential emitters interested in utilizing the CCS technology, amid new funding signals such as the U.S. DOE's $110M for CCUS that highlight momentum. They believe the project holds significant value despite Capital Power's departure.

"We are confident in the long-term viability of the project and continue to actively engage with potential customers," said Enbridge spokesperson Rachel Giroux. "Carbon capture and storage is a critical technology for achieving net-zero emissions, and we believe there is a strong business case for our CCS project."

Enbridge's confidence hinges on several factors. Firstly, they believe there is a growing appetite for CCS technology amongst industrial facilities facing increasing pressure to reduce their carbon footprint. Regulations and carbon pricing mechanisms, including new U.S. EPA power plant rules that test CCS readiness, could further incentivize companies to adopt CCS solutions.

Secondly, Enbridge highlights the potential for capturing emissions from not just power plants but also from other industrial sectors like oil and gas production and clean hydrogen projects in Canada, where reforming processes can generate CO2. This broader application could significantly increase the captured carbon volume and strengthen the project's economic viability.

However, skepticism remains. Critics point to the high upfront costs associated with CCS development and the nascent stage of the technology. They argue that without a guaranteed stream of captured emissions, the project might not be financially sound. Additionally, the long-term safety and effectiveness of large-scale carbon storage solutions remain under scrutiny.

The success of Enbridge's CCS project hinges on attracting new emitters. Replacing Capital Power's contribution will be a significant challenge. Enbridge will need to demonstrate the project's economic viability and navigate the complex regulatory landscape surrounding CCS technology.

The Alberta government's position on CCS is crucial. While the government has expressed support for the technology, the level of financial and regulatory incentives offered will significantly impact investor confidence, especially as the IEA net-zero outlook underscores Canada's need for much more electricity. A clear and stable policy framework will be essential for attracting emitters to the project.

The future of Enbridge's CCS project remains uncertain. Capital Power's withdrawal is a setback, but Enbridge's continued commitment suggests they believe the technology holds promise. Whether they can find enough emitters to justify the project's development will be a critical test. The outcome will have significant implications for the future of CCS technology in Alberta and Canada's broader efforts to achieve net-zero emissions, including Canada-Germany clean energy cooperation that seeks to scale low-carbon fuels.

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Quebec Churchill Falls power deal renewal spotlights Hydro-Que9bec's Labrador hydroelectricity, Churchill River contract extension, Gull Island prospects, and Innu Nation rights, as demand from EV battery manufacturing and the green economy outpaces provincial supply.

Key Points

Extending Quebec's low-price Churchill Falls contract to secure Labrador hydro and address Innu Nation rights.

✅ 1969 contract delivers ~30 TWh at very low fixed price.

✅ Newfoundland seeks higher rates, equity, and consultation.

✅ Innu Nation demands benefits, consent, and land remediation.

As Quebec prepares to ramp up electricity production to meet its ambitious economic goals, the government is trying to extend a power deal that has caused decades of resentment in Newfoundland and Labrador.

Around 15 per cent of Quebec's electricity comes from the Churchill Falls dam in Labrador, through a deal set to expire in 2041 that is widely seen as unfair. Quebec Premier François Legault not only wants to extend the agreement, he wants another dam on the Churchill River and, for now, has closed the door on nuclear power as an option to help make his province what he has called a "world leader for the green economy."

But renewing that contract "won't be easy," Normand Mousseau, scientific director of the Trottier Energy Institute at Polytechnique Montréal, said in a recent interview. Extending the Churchill Falls deal is not essential to meet Quebec's energy plans, but without it, Mousseau said, "we would have some problems."

The Legault government is enticing global companies, such as manufacturers of electric vehicle batteries, to set up shop in the province and access its hydroelectricity. But demand for Quebec's power has exceeded its supply, and Ontario has chosen not to renew a power-purchase deal with Quebec, limiting the government's vision.

Last month, Quebec's hydro utility released its strategic plan calling for a production increase of 60 terawatt hours by 2035, which represents the installed capacity of three of Hydro-Québec's largest facilities. Churchill Falls produces roughly 30 terawatt hours, and Quebec would need to replace that power if it can't strike a deal to extend the contract, Mousseau said.

If Quebec wants to keep buying power from Churchill Falls, the government is going to have to pay more, said Mousseau, who is also a physics professor at Université de Montréal. "We're paying one-fifth of a cent a kilowatt hour — that's not much," he said.

Under the 1969 contract, Quebec assumed most of the financial risk of building the Churchill Falls dam in exchange for the right to buy power at a fixed price. The deal has generated more than $28 billion for Hydro-Québec; it has returned $2 billion to Newfoundland and Labrador.

That lopsided deal has stoked anti-Quebec sentiment in Newfoundland and Labrador and contributed to nationalist politics, including threats of separation from Canada around a decade and a half ago, when Danny Williams was premier, said Jerry Bannister, a history professor at Dalhousie University.

"We tend to forget what it was like during the Williams era — he hauled down the Canadian flag," Bannister said. "There was a type of angry, combative nationalism which defined energy development. And particularly Muskrat Falls, it was payback, it was revenge."

Power from the Muskrat Falls generating station, also on the Churchill River, would be sold to Nova Scotia instead of Quebec. But that project has suffered technical problems and cost overruns since, and as of June 29, the price of Muskrat Falls had reached $13.5 billion; the province had estimated the total cost would be $7.4 billion when it sanctioned the project in 2012.

Anti-Quebec feelings may have subsided, but Bannister said the Churchill Falls deal continues to influence Newfoundland politics.

In September, Premier Andrew Furey said Legault would have to show him the money(opens in a new tab) to extend th Legault's office said Tuesday that discussions are ongoing, while the Newfoundland and Labrador government said in an emailed statement Thursday that it wants to maximize the value of its "assets and future opportunities" along the Churchill River.

Whatever negotiations are happening, Grand Chief Simon Pokue of the Innu Nation of Labrador(opens in a new tab) said he has been left out of them.

Churchill Falls flooded 6,500 square kilometres of traditional Innu land, Pokue said, adding that in response, the Innu Nation filed a $4 billion lawsuit against Hydro-Québec in 2020, which is ongoing.

"A lot of damage has been done to our lands, our land is flooded and we'll never see it again," Pokue said in a recent interview. "Nobody will ever repair that."

As well, a portion of Muskrat Falls profits was supposed to go to the Innu Nation, but the cost overruns and a refinancing deal between the federal government and Newfoundland and Labrador have limited whatever money they will see.

If Legault wants another dam on the Churchill River, at Gull Island, the Innu Nation needs to be paid the kind of money it was expecting from Muskrat Falls, he said.

"You did it once, but you're not going to do it again," Pokue said. "It's not going to start until we are consulted and involved."

Meanwhile, Quebec may face competition for Churchill Falls power, Mousseau said, with at least one Labrador mining company expressing interest in buying a significant portion of its output — though he added that the dam's capacity could be increased. The low price paid by Quebec has meant there has been little incentive to upgrade the plant's turbines.

As demand for electricity rises across the country, Mousseau said he thinks it would be better for provinces to work together, sharing expertise and costs, for example through NB Power deals to import more Quebec electricity as they look across provincial borders to find the best locations for projects, rather than acting as rivals.

"We need to talk and work with other provinces, and some propose an independent planning body to guide this, but for this you need to build confidence, and there's no confidence from the Newfoundland side with respect to Quebec," he said. "So that's a challenge: how do you work on this relationship that has been broken for 50 years?"e contract, but the two premiers have said little since.

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Western Canada Electric Grid could deliver interprovincial transmission, reliability, peak-load support, reserve sharing, and wind and solar integration, lowering costs versus new generation while respecting AESO markets and Crown utility structures.

Key Points

Interprovincial transmission to share reserves, boost reliability, integrate wind and solar, and cut peak capacity costs.

✅ Cuts reserve margins via diversity of peak loads

✅ Enables wind and solar balancing across provinces

✅ Saves ratepayers vs replacing retiring thermal plants

The 2017 Canadian Free Trade Agreement does not do much to encourage provinces to trade electric energy east and west. Would a western Canada electric grid help electricity consumers in the western provinces? Some Alberta officials feel that their electric utilities are investor owned and they perceive the Crown corporations of BC Hydro, SaskPower and Manitoba Hydro to be subsidized by their provincial governments, so an interprovincial electric energy trade would not be on a level playing field.

Because of the limited trade of electric energy between the western provinces, each utility maintains an excessive reserve of thermal and hydroelectric generation greater than their peak loads, to provide a reliable supply during peak load days as grids are increasingly exposed to harsh weather across Canada. This excess does not include variable wind and solar generation, which within a province can’t be guaranteed to be available when needed most.

This attitude must change. Transmission is cheaper than generation, and coordinated macrogrids can further improve reliability and cut costs. By constructing a substantial grid with low profile and aesthetically designed overhead transmission lines, the excess reserve of thermal and hydroelectric generation above the peak electric load can be reduced in each province over time. Detailed assessments will ensure each province retains its required reliability of electric supply.

As the provinces retire aging thermal and coal-fired generators, they only need to replace them to a much lower level, by just enough to meet their future electric loads and Canada's net-zero grid by 2050 goals. Some of the money not spent in replacing retired generation can be profitably invested in the transmission grid across the four western provinces.

But what about Alberta, which does not want to trade electric energy with the other western provinces? It can carry on as usual within the Alberta Electric System Operator’s (AESO) market and will save money by keeping the installed reserve of thermal and hydroelectric generation to a minimum. When Alberta experiences a peak electric load day and some generators are out of service due to unplanned maintenance, it can obtain the needed power from the interprovincial electric grid. None of the other three western provinces will peak at the same time, because of different weather and time zones, so they will have spare capacity to help Alberta over its peak. The peak load in a province only lasts for a few hours, so Alberta will get by with a little help from its friends if needed.

The grid will have no energy flowing on it for this purpose except to assist a province from time to time when it’s unable to meet its peak load. The grid may only carry load five per cent of the time in a year for this purpose. Under such circumstances, the empty grid can then be used for other profitable markets in electric energy. This includes more effective use of variable wind and solar energy, by enabling a province to better balance such intermittent power as well as allowing increased installation of it in every province. This is a challenge for AESO which the grid would substantially ease.

Natural Resources Canada promoted the “Regional Electricity Co-Operative and Strategic Infrastructure” initiative for completion this year and contracted through AESO, alongside an Atlantic grid study to explore regional improvements. This is a first step, but more is needed to achieve the full benefit of a western grid.

In 1970 a study was undertaken to electrically interconnect Britain with France, which was justified based on the ability to reduce reserve generation in both countries. Initially Britain rejected it, but France was partially supportive. In time, a substantial interconnection was built, and being a profitable venture, they are contemplating increasing the grid connections between them.

For the sake of the western consumers of electricity and to keep electricity rates from rising too quickly, as well as allowing productive expansion of wind and solar energy in places like British Columbia's clean energy shift efforts, an electric grid is essential across western Canada.

Dennis Woodford is president of Electranix Corporation in Winnipeg, which studies electric transmission problems, particularly involving renewable energy generators requiring firm connection to the grid.

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China Energy Crisis drives electricity shortages, power cuts, and blackouts as coal prices surge, carbon-neutrality rules tighten, and manufacturing hubs ration energy, disrupting supply chains and industrial output ahead of winter demand peaks.

Key Points

A power shortfall from costly coal, price caps, and emissions targets, causing blackouts and industrial rationing.

✅ Coal prices soar while electricity tariffs are capped

✅ Factories in northeast hubs face rationing and downtime

✅ Supply chains risk delays ahead of winter demand

China is struggling with a severe shortage of electricity which has left millions of homes and businesses hit by power cuts.

Blackouts are not that unusual in the country but this year a number of factors have contributed to a perfect storm for electricity suppliers, including surging electricity demand globally.

The problem is particularly serious in China's north eastern industrial hubs as winter approaches - and is something that could have implications for the rest of the world.

Why has China been hit by power shortages?
The country has in the past struggled to balance electricity supplies with demand, which has often left many of China's provinces at risk of power outages.

During times of peak power consumption in the summer and winter the problem becomes particularly acute.

But this year a number of factors have come together to make the issue especially serious.

As the world starts to reopen after the pandemic, demand for Chinese goods is surging and the factories making them need a lot more power, highlighting China's electricity appetite in recent months.

Rules imposed by Beijing as it attempts to make the country carbon neutral by 2060 have seen coal production slow, even as the country still relies on coal for more than half of its power and as low-emissions generation is set to cover most global demand growth.

And as electricity demand has risen, the price of coal has been pushed up.

But with the government strictly controlling electricity prices, coal-fired power plants are unwilling to operate at a loss, with many drastically reducing their output instead.

Who is being affected by the blackouts?
Homes and businesses have been affected by power cuts as electricity has been rationed in several provinces and regions.

A coal-burning power plant can be seen behind a factory in China"s Inner Mongolia Autonomous Region

The state-run Global Times newspaper said there had been outages in four provinces - Guangdong in the south and Heilongjiang, Jilin and Liaoning in the north east. There are also reports of power cuts in other parts of the country.

Companies in major manufacturing areas have been called on to reduce energy usage during periods of peak demand or limit the number of days that they operate.

Energy-intensive industries such as steel-making, aluminium smelting, cement manufacturing and fertiliser production are among the businesses hardest hit by the outages.

What has the impact been on China's economy?
Official figures have shown that in September 2021, Chinese factory activity shrunk to the lowest it had been since February 2020, when power demand dropped as coronavirus lockdowns crippled the economy.

Concerns over the power cuts have contributed to global investment banks cutting their forecasts for the country's economic growth.

Goldman Sachs has estimated that as much as 44% of the country's industrial activity has been affected by power shortages. It now expects the world's second largest economy to expand by 7.8% this year, down from its previous prediction of 8.2%.

Globally, the outages could affect supply chains, including solar supply chains as the end-of-the-year shopping season approaches.

Since economies have reopened, retailers around the world have already been facing widespread disruption amid a surge in demand for imports.

China's economic planner, the National Development and Reform Commission (NDRC), has outlined a number of measures to resolve the problem, with energy supplies in the northeast of the country as its main priority this winter.

The measures include working closely with generating firms to increase output, ensuring full supplies of coal and promoting the rationing of electricity.

The China Electricity Council, which represents generating firms, has also said that coal-fired power companies were now "expanding their procurement channels at any cost" in order to guarantee winter heat and electricity supplies.

However, finding new sources of coal imports may not be straightforward.

Russia is already focused on its customers in Europe, Indonesian output has been hit by heavy rains and nearby Mongolia is facing a shortage of road haulage capacity,

Are energy shortages around the world connected?
Power cuts in China, UK petrol stations running out of fuel, energy bills jumping in Europe, near-blackouts in Japan and soaring crude oil, natural gas and coal prices on wholesale markets - it would be tempting to assume the world is suddenly in the grip of a global energy drought.

However, it is not quite as simple as that - there are some distinctly different issues around the world.

For example, in the UK petrol stations have run dry as motorists rushed to fill up their vehicles over concerns that a shortage of tanker drivers would mean fuel would soon become scarce.

Meanwhile, mainland Europe's rising energy bills and record electricity prices are due to a number of local factors, including low stockpiles of natural gas, weak output from the region's windmills and solar farms and maintenance work that has put generating operations out of action.
 

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World Bank Energy Policy debates financing for coal, oil, gas, and renewables to fight energy poverty, expand grid reliability, ensure baseload power, and balance climate goals with development finance for affordable, reliable electricity access.

Key Points

It outlines the bank's stance on financing fossil fuels and renewables to expand affordable, reliable electricity.

✅ Focus on energy access, baseload reliability, and poverty alleviation

✅ Debate over coal, gas, and renewables in development finance

✅ Geopolitics: China and Russia fill funding gaps, raising risks

Why isn’t the World Bank using all available energy resources in its global efforts to fight poverty? That’s the question I’ve asked World Bank President David Malpass. Nearly two years ago, the multilateral development bank decided to stop supporting critical coal, oil and gas projects that help people in developing countries escape poverty.

Along with 11 other senators, and as a member who votes on whether to give U.S. taxpayer dollars to the World Bank, I am pressing the bank to lift these restrictions. Developing countries desperately need access to a steady supply of affordable, reliable clean electricity to support economic growth.

The World Bank has pulled funding for critical electricity projects in poor countries, including high-efficiency power stations that are fueled by coal, even as efforts to revitalize coal communities with clean energy have grown.

Despite Kosovo having the world’s fifth-largest reserves of coal, the bank announced it would only support new energy projects from renewable sources going forward. Kosovo’s Minister of Economic Development Valdrin Lluka responded: “We don’t have the luxury to do such experiments in a poor country such as Kosovo. … It is in our national security interest to secure base energy inside our country.”

The World Bank’s misguided move comes as 840 million people worldwide are living without electricity, including 70 percent of sub-Saharan Africa, and as the fall in global energy investment may lead to shortages.

Even more troubling, nearly 3 billion people in developing countries rely on fuels like wood and other biomass for cooking and home heating, resulting in serious health problems and premature deaths, and the pandemic saw widespread electricity shut-offs that deepened energy insecurity. In 2016, household smoke killed an estimated 2.6 million people.

The World Bank’s mission is to lift people out of poverty. The bank is now compromising that mission in favor of a political agenda targeting certain energy sources.

With the World Bank blocking financing to affordable and reliable energy projects, Russia and China are stepping up their investments in order to gain geopolitical leverage.

President Vladimir Putin is pursuing Russian oil and gas projects in Mozambique, Gabon, and Angola. China’s Belt and Road Initiative is supporting traditional energy resources, with 36 percent of its power projects from 2014 to 2017 involving coal. South Africa had to turn to the China Development Bank to fund its $1.5 billion coal-fired power plant.

There are real risks for countries partnering with China and Russia on these projects. Developing countries are facing what some are calling China’s “debt trap” diplomacy. These nations have also raised concerns over safety compliance, unfair business practices, and labor standards.

As the bank’s largest contributor, the United States has a duty to make sure U.S. taxpayer dollars are used wisely and effectively. Every U.S. dollar at the World Bank should make a difference for people in the developing world.

My colleagues and I have asked the bank to pursue an all-of-the-above energy strategy as it strives to achieve its mission to end extreme poverty and promote shared prosperity. We will take the bank’s response into account during the congressional appropriations process.

The United States is a top global energy producer. And yet Democrats running for president are pursuing anti-energy policies that would hurt not only the United States but the entire world, with implications for U.S. national security as well.

Utilizing our abundant energy resources has fueled an American energy renaissance and a booming U.S. economy, even as disruptions in coal and nuclear have strained the grid, with millions of new jobs and higher wages.

People who are struggling to survive and thrive in developing countries deserve the same opportunity to access affordable and reliable sources of power.

As Microsoft founder and global philanthropist Bill Gates has noted of renewables: "Many people experiencing energy poverty live in areas without access to the kind of grids that are needed to make those technologies cheap and reliable enough to replace fossil fuels."

Ultimately, there is a role for all sources of energy to help countries alleviate poverty and improve the education, health and wellbeing of their people.

The solution to ending energy poverty does not lie in limiting options, but in using all available options. The World Bank must recommit to ending extreme poverty by helping countries use all of the world’s abundant energy resources. Let’s end energy poverty now.

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