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Nuclear decarbonization leverages low-carbon electricity, process heat, and hydrogen from advanced reactors and SMRs to electrify industry, buildings, and transport, supporting net-zero strategies and grid flexibility alongside renewables with dispatchable baseload capacity.

Key Points

Nuclear decarbonization uses reactors to supply low-carbon power, heat, and hydrogen, cutting emissions across industry.

✅ Advanced reactors and SMRs enable high-temperature process heat

✅ Nuclear-powered electrolysis and HTSE produce low-carbon hydrogen

✅ District heating from reactors reduces pollution and coal use

By Dr Henri Paillere, Head of the Planning and Economics Studies Section of the IAEA

Decarbonising the power sector will not be sufficient to achieving net-zero emissions, with assessments indicating nuclear may be essential across sectors. We also need to decarbonise the non-power sectors - transport, buildings and industry - which represent 60% of emissions from the energy sector today. The way to do that is: electrification with low-carbon electricity as much as possible; using low-carbon heat sources; and using low-carbon fuels, including hydrogen, produced from clean electricity.
The International Energy Agency (IEA) says that: 'Almost half of the emissions reductions needed to reach net zero by 2050 will need to come from technologies that have not reached the market today.' So there is a need to innovate and push the research, development and deployment of technologies. That includes nuclear beyond electricity.

Today, most of the scenario projections see nuclear's role ONLY in the power sector, despite ongoing debates over whether nuclear power is in decline globally, but increased electrification will require more low-carbon electricity, so potentially more nuclear. Nuclear energy is also a source of low-carbon heat, and could also be used to produce low-carbon fuels such as hydrogen. This is a virtually untapped potential.

There is an opportunity for the nuclear energy sector - from advanced reactors, next-gen nuclear small modular reactors, and non-power applications - but it requires a level playing field, not only in terms of financing today's technologies, but also in terms of promoting innovation and supporting research up to market deployment. And of course technology readiness and economics will be key to their success.

On process heat and district heating, I would draw attention to the fact there have been decades of experience in nuclear district heating. Not well spread, but experience nonetheless, in Russia, Hungary and Switzerland. Last year, we had two new projects. One floating nuclear power plant in Russia (Akademik Lomonosov), which provides not only electricity but district heating to the region of Pevek where it is connected. And in China, the Haiyang nuclear power plant (AP1000 technology) has started delivering commercial district heating. In China, there is an additional motivation to reducing emissions, namely to cut air pollution because in northern China a lot of the heating in winter is provided by coal-fired boilers. By going nuclear with district heating they are therefore cutting down on this pollution and helping with reducing carbon emissions as well. And Poland is looking at high-temperature reactors to replace its fleet of coal-fired boilers and so that's a technology that could also be a game-changer on the industry side.

There have also been decades of research into the production of hydrogen using nuclear energy, but no real deployment. Now, from a climate point of view, there is a clear drive to find substitute fuels for the hydrocarbon fuels that we use today, and multiple new nuclear stations are seen by industry leaders as necessary to meet net-zero targets. In the near term, we will be able to produce hydrogen with electrolysis using low-carbon electricity, from renewables and nuclear. But the cheapest source of low-carbon power is from the long-term operation of existing nuclear power plants which, combined with their high capacity factors, can give the cheapest low-carbon hydrogen of all.

In the mid to long term, there is research on-going with processes that are more efficient than low-temperature electrolysis, which is high temperature steam electrolysis or thermal splitting of water. These may offer higher efficiencies and effectiveness but they also require advanced reactors that are still under development. Demonstration projects are being considered in several countries and we at the IAEA are developing a publication that looks into the business opportunities for nuclear production of hydrogen from existing reactors. In some countries, there is a need to boost the economics of the existing fleet, especially in the electricity systems where you have low or even negative market prices for electricity. So, we are looking at other products that have higher values to improve the competitiveness of existing nuclear power plants.

The future means not only looking at electricity, but also at industry and transport, and so integrated energy systems. Electricity will be the main workhorse of our global decarbonisation effort, but through heat and hydrogen. How you model this is the object of a lot of research work being done by different institutes and we at the IAEA are developing some modelling capabilities with the objective of optimising low-carbon emissions and overall costs.

This is just a picture of what the future might look like: a low-carbon power system with nuclear lightwater reactors (large reactors, small modular reactors and fast reactors) drawing on the green industrial revolution reactor waves in planning; solar, wind, anything that produces low-carbon electricity that can be used to electrify industry, transport, and the heating and cooling of buildings. But we know there is a need for high-temperature process steam that electricity cannot bring but which can be delivered directly by high-temperature reactors. And there are a number of ways of producing low-carbon hydrogen. The beauty of hydrogen is that it can be stored and it could possibly be injected into gas networks that could be run in the future on 100% hydrogen, and this could be converted back into electricity.

So, for decarbonising power, there are many options - nuclear, hydro, variable renewables, with renewables poised to surpass coal in global generation, and fossil with carbon capture and storage - and it's up to countries and industries to invest in the ones they prefer. We find that nuclear can actually reduce the overall cost of systems due to its dispatchability and the fact that variable renewables have a cost because of their intermittency. There is a need for appropriate market designs and the role of governments to encourage investments in nuclear.

Decarbonising other sectors will be as important as decarbonising electricity, from ways to produce low-carbon heat and low-carbon hydrogen. It's not so obvious who will be the clear winners, but I would say that since nuclear can produce all three low-carbon vectors - electricity, heat and hydrogen - it should have the advantage.
We at the IAEA will be organising a webinar next month with the IEA looking at long-term nuclear projections in a net-zero world, building on IAEA analysis on COVID-19 and low-carbon electricity insights. That will be our contribution from the point of view of nuclear to the IEA's special report on roadmaps to net zero that it will publish in May.

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Quebec Hydropower Export Retaliation examines using electricity exports to counter U.S. tariffs amid Canada-U.S. trade tensions, weighing clean energy supply, grid reliability, energy security, legal risks, and long-term market impacts.

Key Points

Using Quebec electricity exports as leverage against U.S. tariffs, and its economic, legal, and diplomatic consequences.

✅ Revenue loss for Quebec and higher costs for U.S. consumers

✅ Risk of legal disputes under trade and energy agreements

✅ Long-term erosion of market share and grid cooperation

As trade tensions between Canada and the United States continue to escalate, with electricity exports at risk according to recent reporting, discussions have intensified around potential Canadian responses to the imposition of U.S. tariffs. One of the proposals gaining attention is the idea of reducing or even halting the export of energy from Quebec to the U.S. This measure has been suggested by some as a potential countermeasure to retaliate against the tariffs. However, experts and industry leaders are urging caution, emphasizing that the consequences of such a decision could have significant economic and diplomatic repercussions for both Canada and the United States.

Quebec plays a critical role in energy trade, particularly in supplying hydroelectric power to the United States, especially to the northeastern states, including New York where tariffs may spike energy prices according to analysts, strengthening the case for stable cross-border flows. This energy trade is deeply embedded in the economic fabric of both regions. For Quebec, the export of hydroelectric power represents a crucial source of revenue, while for the U.S., it provides access to a steady and reliable supply of clean, renewable energy. This mutually beneficial relationship has been a cornerstone of trade between the two countries, promoting economic stability and environmental sustainability.

In the wake of recent U.S. tariffs on Canadian goods, some policymakers have considered using energy exports as leverage, echoing threats to cut U.S. electricity exports in earlier disputes, to retaliate against what is viewed as an unfair trade practice. The idea is to reduce or stop the flow of electricity to the U.S. as a way to strike back at the tariffs and potentially force a change in U.S. policy. On the surface, this approach may appear to offer a viable means of exerting pressure. However, experts warn that such a move would be fraught with significant risks, both economically and diplomatically.

First and foremost, Quebec's economy is heavily reliant on revenue from hydroelectric exports to the U.S. Any reduction in these energy sales could have serious consequences for the province's economic stability, potentially resulting in job losses and a decrease in investment. The hydroelectric power sector is a major contributor to Quebec's GDP, and recent events, including a tariff threat delaying a green energy bill in Quebec, illustrate how trade tensions can ripple through the policy landscape, while disrupting this source of income could harm the provincial economy.

Additionally, experts caution that reducing energy exports could have long-term ramifications on the energy relationship between Quebec and the northeastern U.S. These two regions have developed a strong and interconnected energy network over the years, and abruptly cutting off the flow of electricity could damage this vital partnership. Legal challenges could arise under existing trade agreements, and even as tariff threats boost support for Canadian energy projects among some stakeholders, the situation would grow more complex. Such a move could also undermine trust between the two parties, making future negotiations on energy and other trade issues more difficult.

Another potential consequence of halting energy exports is that U.S. states may seek alternative sources of energy, diminishing Quebec's market share in the long run. As the U.S. has a growing demand for clean energy, especially as it looks to transition away from fossil fuels, and looks to Canada for green power in several regions, cutting off Quebec’s electricity could prompt U.S. states to invest in other forms of energy, including renewables or even nuclear power. This could have a lasting effect on Quebec's position in the U.S. energy market, making it harder for the province to regain its footing.

Moreover, reducing or ceasing energy exports could further exacerbate trade tensions, leading to even greater economic instability. The U.S. could retaliate by imposing additional tariffs on Canadian goods or taking other measures that would negatively impact Canada's economy. This could create a cycle of escalating trade barriers that would hurt both countries and undermine the broader North American trade relationship.

While the concept of using energy exports as a retaliatory tool may seem appealing to some, the experts' advice is clear: the potential economic and diplomatic costs of such a strategy outweigh the short-term benefits. Quebec’s role as an energy supplier to the U.S. is crucial to its own economy, and maintaining a stable, reliable energy trade relationship is essential for both parties. Rather than escalating tensions further, it may be more prudent for Canada and the U.S. to seek diplomatic solutions that preserve trade relations and minimize harm to their economies.

While the idea of using Quebec’s energy exports as leverage in response to U.S. tariffs may appear attractive on the surface, and despite polls showing support for tariffs on energy and minerals among Canadians, it carries significant risks. Experts emphasize the importance of maintaining a stable energy export strategy to protect Quebec’s economy and preserve positive diplomatic relations with the U.S. Both countries have much to lose from further escalating trade tensions, and a more measured approach is likely to yield better outcomes in the long run.

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Tesla Electric UK Expansion signals retail energy entry, leveraging Powerwall VPPs for grid services, dynamic pricing, and energy trading, building on Texas success and Octopus Energy ties to buy and sell electricity automatically.

Key Points

Tesla's plan to launch Tesla Electric in the UK, using Powerwall VPPs to retail energy, trade power, and hedge peaks.

✅ Retail energy model built on Powerwall VPP aggregation

✅ Automated buy-sell arbitrage with dynamic pricing

✅ Leverages prior UK approval and Octopus Energy ties

According to a new job posting, Tesla Electric, Tesla’s new electric utility division, is preparing to expand in the United Kingdom as regions such as California grid planners look to electric vehicles for stability to manage demand.

Late last year, after gaining experience through its virtual power plants (VPPs), including response during California blackouts that pressured the grid, Tesla took things a step further with the launch of “Tesla Electric.”

Instead of reacting to specific “events” and providing services to your local electric utilities through demand response programs, as Tesla Powerwall owners have done in VPPs in California, Tesla Electric is actively and automatically buying and selling electricity for Tesla Powerwall owners – providing a buffer against peak prices.

The company is essentially becoming an energy retailer, aligning with a major future for its energy business envisioned by leadership.

Tesla Electric is currently only available to Powerwall owners in Texas, but the company has plans to expand its products through this new division.

We recently reported on Tesla Electric customers in Texas making as much as $150 a day selling electricity back to the grid through the program.

Now Tesla is looking to expand Tesla Electric to the UK, where grid capacity for rising EV demand remains a key consideration.

The company has listed a new job posting for a role called “Head of Operations, Tesla Electric – Retail Energy.”

This has been in the works for a while now. Tesla used to have a partnership with Octopus Energy in the UK for special electricity rates for its owners, during a period when UK EV inquiries surged amid a fuel supply crisis, but it seemed to be a stepping stone before it would itself become an energy provider in the market.

In 2020, Tesla was officially approved as an electricity retailer in the UK. Now it looks like Tesla is going to use this approval with the launch of Tesla Electric.
 

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ERCOT Texas Fall Grid Forecast outlines ample power supply, planned maintenance outages, and grid reliability, citing PUC oversight and Gov. Abbott's remarks, with seasonal assessment noting mild demand yet climate risks and conservation alerts.

Key Points

ERCOT's seasonal outlook for Texas on fall power supply, outages, and reliability expectations under PUC oversight.

✅ Projects sufficient supply in October and November

✅ Many plants scheduled offline for maintenance

✅ Notes PUC oversight and Abbott's confidence

Gov. Greg Abbott said Tuesday that the Texas power grid is prepared for the fall months and referenced a new seasonal forecast by the state’s grid operator, which typically does not draw much attention to its fall and spring grid assessments because of the more mild temperatures during those seasons.

Tuesday’s new forecast by the Electric Reliability Council of Texas showed that there should be plenty of power supply to meet demand in October and November. It also showed that many Texas power plants are scheduled to be offline this fall for maintenance work. Texas power plants usually plan to go down in the fall and spring for repairs to improve reliability ahead of the more extreme temperatures in winter and summer, when Texans crank up their heat and air conditioning and raise demand for power.

ERCOT for at least a decade announced its seasonal forecasts, but did not do so on Tuesday. The grid operator stopped announcing the reports after the 2021 winter storm event. A spokesperson for the grid operator, which posted the report to its website midday without notifying the public or power industry stakeholders, said there were no plans to discuss the latest forecast and referred questions about it to the Public Utility Commission, which oversees ERCOT. Abbott appoints the board of the PUC.

Abbott on Tuesday expressed his confidence about the grid in a news release, which included photos of the governor sitting at a table with incoming ERCOT CEO Pablo Vegas, outgoing interim CEO Brad Jones and Public Utility Commission Chair Peter Lake.

“The State of Texas continues to monitor the reliability of our electric grid, and I thank ERCOT and PUC for their hard work to implement bipartisan reforms we passed last year and for their proactive leadership to ensure our grid is stronger than ever before,” Abbott said in the release.

Abbott has not previously shared or called attention to ERCOT’s forecasts as he did on Tuesday.

Up for reelection this fall, Abbott has faced continued criticism, including from the Sierra Club over his handling of the 2021 deadly power grid disaster, when extended freezing temperatures shut down natural gas facilities and power plants, which rely on each other to keep electricity flowing. The resulting blackouts left millions of Texans without power for days in the cold, and hundreds of people died.

ERCOT’s forecasts for fall and spring are typically the least worrisome seasonal forecasts, energy experts said, because temperatures are usually milder in between summer and winter, even as ERCOT has issued an RFP to procure winter capacity to address shortages, so demand for power usually does not skyrocket like it does during extreme temperatures.

But they’ve warned that climate change could potentially lead to more extreme temperatures during times when Texas hasn’t experienced such weather in the past. For example, in early May six power plants unexpectedly broke down when a spring heat wave drove power demand up and highlighted broader heat-related blackout risks across the grid. ERCOT asked Texans to conserve electricity at home at the time.

Abbott released the seasonal report at a time when he has asserted unprecedented control over ERCOT. Although he had no formal role in ERCOT’s search for a new permanent CEO, he put a stranglehold on the process, The Texas Tribune previously reported. Since the winter storm, Abbott’s office has also dictated what information about the power grid ERCOT has released to the public.

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UK Hydrogen Storage Caverns enable long-duration, low-carbon electricity balancing, storing surplus wind and solar power as green hydrogen in salt formations to enhance grid reliability, energy security, and net zero resilience by 2035 and 2050.

Key Points

They are salt caverns storing green hydrogen to balance wind and solar, stabilizing a low-carbon UK grid.

✅ Stores surplus wind and solar as green hydrogen in salt caverns

✅ Enables long-duration, low-carbon grid balancing and security

✅ Complements wind and solar; reduces dependence on flexible CCS

The U.K. government must kick-start the construction of large-scale hydrogen storage facilities if it is to meet its pledge that all electricity will come from low-carbon electricity sources by 2035 and reach legally binding net zero targets by 2050, according to a report by the Royal Society.

The report, "Large-scale electricity storage," published Sep. 8, examines a wide variety of ways to store surplus wind and solar generated electricity—including green hydrogen, advanced compressed air energy storage (ACAES), ammonia, and heat—which will be needed when Great Britain's electricity generation is dominated by volatile wind and solar power.

It concludes that large scale electricity storage is essential to mitigate variations in wind and sunshine, particularly long-term variations in the wind, and to keep the nation's lights on. Storing most of the surplus as hydrogen, in salt caverns, would be the cheapest way of doing this.

The report, based on 37 years of weather data, finds that in 2050 up to 100 Terawatt-hours (TWh) of storage will be needed, which would have to be capable of meeting around a quarter of the U.K.'s current annual electricity demand. This would be equivalent to more than 5,000 Dinorwig pumped hydroelectric dams. Storage on this scale, which would require up to 90 clusters of 10 caverns, is not possible with batteries or pumped hydro.

Storage requirements on this scale are not currently foreseen by the government, and the U.K.'s energy transition faces supply delays. Work on constructing these caverns should begin immediately if the government is to have any chance of meeting its net zero targets, the report states.

Sir Chris Llewellyn Smith FRS, lead author of the report, said, "The need for long-term storage has been seriously underestimated. Demand for electricity is expected to double by 2050 with the electrification of heat, transport, and industrial processing, as well as increases in the use of air conditioning, economic growth, and changes in population.

"It will mainly be met by wind and solar generation. They are the cheapest forms of low-carbon electricity generation, but are volatile—wind varies on a decadal timescale, so will have to be complemented by large scale supply from energy storage or other sources."

The only other large-scale low-carbon sources are nuclear power, gas with carbon capture and storage (CCS), and bioenergy without or with CCS (BECCS). While nuclear and gas with CCS are expected to play a role, they are expensive, especially if operated flexibly.

Sir Peter Bruce, vice president of the Royal Society, said, "Ensuring our future electricity supply remains reliable and resilient will be crucial for our future prosperity and well-being. An electricity system with significant wind and solar generation is likely to offer the lowest cost electricity but it is essential to have large-scale energy stores that can be accessed quickly to ensure Great Britain's energy security and sovereignty."

Combining hydrogen with ACAES, or other forms of storage that are more efficient than hydrogen, could lower the average cost of electricity overall, and would lower the required level of wind power and solar supply.

There are currently three hydrogen storage caverns in the U.K., which have been in use since 1972, and the British Geological Survey has identified the geology for ample storage capacity in Cheshire, Wessex and East Yorkshire. Appropriate, novel business models and market structures will be needed to encourage construction of the large number of additional caverns that will be needed, the report says.

Sir Chris observes that, although nuclear, hydro and other sources are likely to play a role, Britain could in principle be powered solely by wind power and solar, supported by hydrogen, and some small-scale storage provided, for example, by batteries, that can respond rapidly and to stabilize the grid. While the cost of electricity would be higher than in the last decade, we anticipate it would be much lower than in 2022, he adds.

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Manitoba Hydro Privatization Debate centers on subsidiaries, Crown corporation governance, clean energy priorities, and electricity rates, as board terms shift oversight and transparency, sparking concerns about sell-offs and government control.

Key Points

A dispute over Hydro's governance, subsidiaries, electricity rates, and clean energy amid fears of partial privatization.

✅ Rewritten terms allow subsidiaries and shift board duties.

✅ Low rates and clean energy mandates softened in guidance.

✅ Govt cites Hydro Act; NDP warns of sell-off risks.

The board of Manitoba Hydro is being reminded it can divvy up some of the utility's work to subsidiaries — which the NDP is decrying as a step toward privatization. 

A sentence seemingly granting the board permission to create subsidiaries was included in the board's new terms of reference, which the NDP raised during question period Wednesday. 

The document also eliminated references asking Manitoba Hydro to keep electricity rates low, even as rate hike hearings proceed, and supply power in an environmentally-friendly fashion.

NDP raises spectre of Manitoba Hydro's privatization with new CEO
"They're essentially taking the heart out of Manitoba Hydro," NDP leader Wab Kinew said.

Cheap, clean energy is the basis by which the Crown corporation was formed, even as scaled-back rate increases are planned for next year, he said. 

"That's the whole reason we created this utility in the first place."

Another addition to the board's guidelines include stating the corporation is responsible to the government minister, who must be "proactively informed" when significant issues arise. 

The provincial government, however, says the rewritten terms of reference was the directive of the Manitoba Hydro board and not itself.

CBC's requests to the government for an interview were directed to Manitoba Hydro.

In an interview, Manitoba Hydro spokesperson Scott Powell said the energy utility has undergone no legislative changes, and is still governed by the Manitoba Hydro Act. 

The terms of reference were altered to align the board's duties with the new act overseeing Crown corporations, Powell said.

"Whether you have one or two words different in the terms of reference, the essence of the company hasn't changed."

While the new terms of reference no longer instructs the corporation to ensure an "environmentally responsible supply of energy for Manitobans," it encourages the board to "promote economy and efficiency in all phases of power generation and distribution."

On the cost to ratepayers, the updated directions asks the utility to deliver "safe, reliable energy services at a fair price," a standard clarified by a recent appeal court ruling on First Nations rates, but the board is not specifically instructed with keeping electricity rates low. 

Kinew contends the added sentence on subsidiaries permits Hydro to be broken off and sold for parts, although the terms of reference does not specify if any subsidiary would be wholly owned by Hydro or contracted to a private company.

Powell said Manitoba Hydro has been permitted to create subsidiaries since 1997, and nothing has changed since.

Kinew warned about Hydro's privatization last week when Jay Grewal was announced as Hydro's incoming CEO and president.

She was employed with B.C. Hydro when then-premier Gordon Campbell — hired by the Manitoba government to investigate costly overruns on two electricity megaprojects — sold off segments of the utility.

She then became managing director of Accenture, a global management consulting firm, which acquired several B.C. Hydro departments.

During question period Wednesday, Pallister disputed that Manitoba Hydro is bound to be sold.

He slammed the NDP's "Americanization strategy" of producing more electricity than it is capable of selling, which has saddled ratepayers with billions in debt and prompted proposed 2.5% annual increases in coming years. 

The makeup of the Hydro board has undergone a complete turnover in under a year, a contrast to Ontario's Hydro One shakeup vow during that period.

Nine of the 10 members resigned en masse this March over an impasse with the Pallister government. The lone holdover, Cliff Graydon, was dismissed from his post last month after the Progressive Conservatives removed him from caucus. 

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