Gas emanating from rotting garbage in a Montreal-area landfill will power a Cascades Inc. paper mill under a three-company agreement announced recently.
Intersan, a unit of Canadian Waste Services Inc., in turn owned by Houston-based Waste Management Inc., will provide the methane from its bioreactor project at the Sainte-Sophie landfill north of Montreal.
Gaz Metro LP, Quebec's leading natural gas distributor, will transport the gas 13 kilometres through a new $8-million underground pipeline to the Cascades fine paper plant in Saint-Jerome.
Cascades will invest $2 million to convert its plant to run on the gas, and based on expected savings "plans a short return on its investment."
Subject to approval by the Regie de l'energie du Quebec, supply from Intersan is to begin by the end of 2004. The arrangement is forecast to meet a large part of the Saint-Jerome plant's energy requirements for the next 10 years.
"While offering the advantage of lowering our production costs, this unique project also translates into enormous environmental gains," stated Denis Jean, president of the Cascades fine paper division.
The Sainte-Sophie landfill, owned by Waste Management, receives a million tonnes a year of municipal trash from the North Shore and city of Laval.
Intersan vice-president Hubert Bourque said the bioreactor complex, which costs about $10 million, produces 1.2 billion cubic feet a year of landfill gas -- half methane and half carbon dioxide.
Cascades is the first commercial client for the three-year-old project, which recirculates leachate — garbage juice — through the landfill waste, speeding decomposition and the generation of methane which is collected by an array of pipes.
Until now, the gas has been flared off.
Cascades will keep its conventional gas connection, but indicated the landfill gas could fill 85 to 90 per cent of the plant's needs.
"Our site is a genuine gas deposit that offers a useful, clean and affordable source of energy," Intersan's Bourque said.
"Intersan is particularly proud to operate a facility that will actively help produce green energy and contribute to the success of a major local company."
The companies declined to specify the price of the landfill gas, but Bourque said it represents a "significant" saving over the cost of natural gas carried by pipeline from Western Canada.
For Gaz Metro, landfill gas holds out the prospect of new supplies.
"Well within our core business of distributing gas throughout Quebec, our involvement in this project is an assurance of efficiency, reliability and safety," said Gaz Metro vice-president Sophie Brochu.
"Landfill gas conversion is a large step towards sustainable development. Gaz Metro is proud to be associated with this project and is actively developing others."
Cascades division president Jean said the development "will demonstrate the energy potential and environmental advantages of landfill gas conversion."
The $2 million plant refit, largely to upgrade gas injectors but possibly to add a new boiler, is necessary because of the 50 per cent carbon dioxide content of the landfill gas, unlike natural gas which is almost pure methane.
The CO2 is not regarded as an additional greenhouse-gas pollutant, because it is generated naturally by the degradation of organic material.
Waste Management operates 69 similar landfill-gas plants in the United States, but the Sainte-Sophie site is its first in Canada.
Cascades, one of Canada's largest forestry companies with 14,100 employees and 2002 revenue of $3.4 billion, manufactures tissue, fine papers and, through its Norampac joint venture, cardboard packaging.
Estonia energy prices 2021 show sharp electricity hikes versus the EU average, mixed natural gas trends, kWh tariffs on Nord Pool spiking, and VAT, taxes, and support measures shaping household bills.
Key Points
EU-high electricity growth, early gas dip, then Nord Pool spikes; taxes, VAT, and subsidies shaped energy bills.
✅ Electricity up 7% on year; EU average 2.8% in H1 2021.
✅ Gas fell 1% in H1; later spiked with global market.
✅ VAT, taxes, excise and aid impacted household costs.
Estonia saw one of the highest rates in growth of electricity prices in the first half of 2021, compared with the same period in key trends in 2020 across Europe. These figures were posted before the more recent, record level of electricity and natural gas prices; the latter actually dropped slightly in Estonia in the first half of the year.
While electricity prices rose 7 percent on year in the first half of 2021 in Estonia, the average for the EU as a whole, where energy prices drove inflation across the bloc, stood at 2.8 percent over the same period, BNS reports.
Hungary (€10 per 100 Kwh) and Bulgaria (€10.20 per 100 Kwh) saw the lowest electricity prices EU-wide, while at €31.9 per KWH, Germany's power prices posted the most expensive rate, while Denmark, Belgium and Ireland also had high prices, in excess of €25 per Kwh.
Slovenia saw the highest electricity price rise, at 15 percent, and even the United States' electricity prices saw their steepest rise in decades during the same era, while Estonia was in third place, joint with Romania at 7 percent as noted, and behind Poland (8 percent).
Lithuania, on the other hand, experienced the third highest electricity price fall over the first half of 2021, compared with the same period in 2020, at 6 percent, behind only Cyprus (7 percent) and the Netherlands (10 percent, largely due to a tax cut).
Urmas Reinsalu: VAT on electricity, gas and heating needs to be lowered The EU average price of electricity was €21.9 percent per Kwh, with taxes and excise accounting for 39 percent of this, even as prices in Spain surged across the day-ahead market.
Estonia has also seen severe electricity price rises in the second half of the year so far, with records set and then promptly broken several times earlier in October, while an Irish electricity provider raised prices amid similar pressures, and a support package for low income households rolled out for the winter season (October to March next year). The price on the Nord Pool market as of €95.01 per Kwh; a day earlier it had stood at €66.21 per Kwh, while on October 19 the price was €140.68 per Kwh.
Gas prices Natural gas prices to household, meanwhile, dropped in Estonia over the same period, at a sharper rate (1 percent) than the EU average (0.5 percent), according to Eurostat.
Gas prices across the EU were lowest in Lithuania (€2.8 per 100 Kwh) and highest in the Netherlands (€9.6 per KWH), while the highest growth was seen in Denmark (19 percent), in the first half of 2021.
Natural gas prices dropped in 20 member states, however, with the largest drop again coming in Lithuania (23 percent).
The average price of natural gas EU-side in the first half of 2021 was €6.4, and taxes and excise duties accounted on average for 36 percent of the total.
The second half of the year has seen steep gas price rises in Estonia, largely the result of increases on the world market, though European gas benchmarks later fell to pre-Ukraine war levels.
Geothermal Emergency Permitting accelerates BLM approvals on public lands via categorical exclusions for exploratory drilling and geophysical surveys, boosting domestic energy security, cutting timelines by up to a year, and streamlining low-impact reviews.
Key Points
A policy fast-tracking geothermal exploration on public lands, using BLM categorical exclusions to cut review delays.
✅ Focused on public lands to enhance energy security
In a significant policy shift, the U.S. Department of the Interior has introduced emergency permitting procedures aimed at expediting the development of geothermal energy projects. This initiative, announced on May 30, 2025, is part of a broader strategy to enhance domestic energy production, seen in proposals to replace Obama's power plant overhaul and reduce reliance on foreign energy sources.
Background and Rationale
The decision to fast-track geothermal energy projects comes in the wake of President Donald Trump's declaration of a national energy emergency, which faces a legal challenge from Washington's attorney general, on January 20, 2025. This declaration cited high energy costs and an unreliable energy grid as threats to national security and economic prosperity. While the emergency order includes traditional energy resources such as oil, gas, coal, and uranium and nuclear energy resources, it notably excludes renewable sources like solar, wind, and hydrogen from its scope.
Geothermal energy, which harnesses heat from beneath the Earth's surface to generate electricity, is considered a reliable and low-emission energy source. However, its development has been hindered by lengthy permitting processes and environmental reviews, with recent NEPA rule changes influencing timelines. The new emergency permitting procedures aim to address these challenges by streamlining the approval process for geothermal projects.
Key Features of the Emergency Permitting Procedures
Under the new guidelines, the Bureau of Land Management (BLM) has adopted categorical exclusions to expedite the review and approval of geothermal energy exploration on public lands. These exclusions allow for faster permitting of low-impact activities, such as drilling exploratory wells and conducting geophysical surveys, without the need for extensive environmental assessments.
Additionally, the BLM has proposed a new categorical exclusion that would apply to operations related to the search for indirect evidence of geothermal resources. This proposal is currently open for public comment and, if finalized, would further accelerate the discovery of new geothermal resources on public lands.
Expected Impact on Geothermal Energy Development
The implementation of these emergency permitting procedures is expected to significantly reduce the time and cost associated with developing geothermal energy projects. According to the Department of the Interior, the new measures could cut permitting timelines by up to a year for certain types of geothermal exploration activities.
This acceleration in project development is particularly important given the untapped geothermal potential in regions like Nevada, which is home to some of the largest undeveloped geothermal resources in the country.
Industry and Environmental Reactions
The geothermal industry has largely welcomed the new permitting procedures, viewing them as a necessary step to unlock the full potential of geothermal energy. Industry advocates argue that reducing permitting delays will facilitate the deployment of geothermal projects, contributing to a more reliable and sustainable energy grid amid debates over electricity pricing changes that affect market signals.
However, the exclusion of solar and wind energy projects from the emergency permitting procedures has drawn criticism from some environmental groups. Critics argue that a comprehensive approach to energy development should include all renewable sources, not just geothermal, to effectively address climate change, as reflected in new EPA pollution limits for coal and gas power plants, and promote energy sustainability.
The U.S. government's move to implement emergency permitting procedures for geothermal energy development marks a significant step toward enhancing domestic energy production and reducing reliance on foreign energy sources. By streamlining the approval process for geothermal projects, the administration aims to accelerate the deployment of this reliable and low-emission energy source. While the exclusion of other renewable energy sources from the emergency procedures has sparked debate, especially after states like California halted an energy rebate program during a federal freeze, the focus on geothermal energy underscores its potential role in the nation's energy future.
Rolls-Royce and Exelon UKSMR Partnership accelerates factory-built small modular reactors, nuclear power, clean energy, 440MW units, advanced manufacturing, fleet deployment, net zero goals, and resilient, low-cost baseload generation in the UK and globally.
Key Points
A partnership to deploy factory-built SMR stations, providing 440MW low-carbon baseload for the UK and export markets.
✅ 440MW factory-built SMR units with rapid modular assembly
✅ Exelon to operate and enhance high capacity factors
✅ Supports UK net zero, jobs, and export-led manufacturing
Rolls-Royce and Exelon Generation have signed a Memorandum of Understanding to pursue the potential for Exelon Generation to operate compact nuclear power stations both in the UK and internationally, including markets such as Canada where New Brunswick SMR questions are prompting public debate today.
Exelon Generation will be using their operational experience to assist Rolls Royce in the development and deployment of the UKSMR.
Rolls-Royce is leading a consortium that is designing a low-cost factory built nuclear power station, known as a small modular reactor (SMR), with UK mini-reactor approval anticipated as development progresses. Its standardised, factory-made components and advanced manufacturing processes push costs down, while the rapid assembly of the modules and components inside a weatherproof canopy on the power station site itself avoid costly schedule disruptions.
The consortium is working with its partners and UK Government to secure a commitment for a fleet of factory built nuclear power stations, each providing 440MW of electricity, to be operational within a decade, helping the UK meet its net zero obligations in line with the green industrial revolution policy set out by government. A fleet deployment in the UK will lead to the creation of new factories that will make the components and modules which will help the economy recover from the Covid-19 pandemic and pave the way for significant export opportunities as well.
The consortium members feature the best of nuclear engineering, construction and infrastructure expertise in Assystem, Atkins, BAM Nuttall, Jacobs, Laing O'Rourke, National Nuclear Laboratory, Nuclear Advanced Manufacturing Research Centre, Rolls-Royce and TWI. Exelon will add valuable operational experience to the team.
Tom Samson, interim Chief Executive Officer of the UKSMR consortium, said: 'Nuclear power is central to tackling climate change and economic recovery, but it must be affordable, reliable and investable and the way we manufacture and assemble our power station brings its cost down to be comparable with offshore wind.
'It's a compelling proposition that could draw new players into the UK's power generation landscape, improving choice for consumers and providing uninterrupted low carbon energy to homes and businesses.
'The opportunity to partner with Exelon is a very exciting prospect for our program, complementing our existing Consortium partnerships with one of the world's largest nuclear operator adds an important dimension to our growth ambitions, embodies the strength of the UK and USA alliance on nuclear matters and reflects wider international moves, such as a Canadian premiers' SMR initiative to accelerate technology development, and offers our future customers the ability to achieve the highest performance standards associated with Exelon's outstanding operational track record.'
The power stations will be built by the UKSMR consortium, before being handed over to be operated by power generation companies. Exelon Generation will work closely with the consortium during the pre-operation period. Exelon Nuclear operates 21 nuclear reactors in America, and U.S. regulators recently issued a final safety evaluation for a NuScale SMR that underscores momentum in the sector. The Exelon nuclear fleet is an integral part of the U.S. clean power mix; it produces more than 158 million megawatt-hours of clean electricity every year.
Bryan Hanson, EVP and COO of Exelon Generation said: 'We believe that SMRs are a crucial part of the world's clean energy mix, as projects like Darlington SMRs advance in Ontario. With our experience both in the US and internationally, Exelon is confident that we can help Rolls Royce ensure SMRs play a key role in the UK's energy future. We've had a very strong record of performance for 20 consecutive years, with a 2019 capacity factor of 95.7 percent. We will leverage this experience to achieve sustainably high capacity factors for the UKSMRs.'
Ralph Hunter, Managing Director of Exelon Nuclear Partners, who runs Exelon's international clean energy business, said: 'We have a strong track record of success to be the operator of choice for the UKSMR. We will help develop operational capability, training and human capacity development in the UK, as utilities such as Ontario Power Generation commit to SMRs abroad, ensuring localisation of skills and a strong culture of safety, performance and efficiency.'
By 2050 a full UK programme of a fleet of factory built nuclear power stations in the UK could create:
Up to 40,000 jobs GBP52BN of value to the UK economy GBP250BN of exports
The current phase of the programme has been jointly funded by all consortium members and UK Research and Innovation.
Nova Scotia Power solar charge proposes an $8/kW monthly system access fee on net metering customers, citing grid costs. UARB review, carbon credits, rate hikes, and solar industry impacts fuel political and consumer backlash.
Key Points
A proposed $8/kW monthly grid access fee on net metered solar customers, delayed to Feb 1, 2023, pending UARB review.
✅ $8/kW monthly system access fee on net metering
✅ Delay to Feb 1, 2023 after industry and political pushback
✅ UARB review; debate over grid costs and carbon credits
Nova Scotia Power has pushed back by a year the start date of a proposed new charge for customers who generate electricity and sell it back to the grid, following days of concern from the solar industry and politicians worried that it will damage the sector.
The company applied to the Nova Scotia Utility and Review Board (UARB) last week for various changes, including a "system access charge" of $8 per kilowatt monthly on net metered installations, and the province cannot order the utility to lower rates under current law. The vast majority of the province's 4,100 net metering customers are residential customers with solar power, according to the application.
The proposed charge would have come into effect Tuesday if approved, but Nova Scotia Power said in a news release Tuesday it will change the date in its filing from Feb. 1, 2022, to Feb. 1, 2023.
"We understand that the solar industry was taken off guard," utility CEO Peter Gregg said in an interview.
"There could have been an opportunity to have more conversations in advance."
Gregg said the utility will meet with members of the solar industry over the next year to work on finding solutions that support the sector's growth, while addressing what NSP sees as an inequity in the net metering system.
NSP recognized that customers who choose solar invest a significant amount and pay for the electricity they use, but they don't pay for costs associated with accessing the electrical grid when they need energy, such as on cold winter evenings when the sun is not shining.
"I know that's hit a nerve, but it doesn't take away the fact that it is an issue," Gregg said.
He said this is an issue utilities are navigating around North America, where seasonal rate designs have sparked consumer backlash in New Brunswick, and NSP is open to hearing ideas for other models of charges or fees.
The utility's suggested system access charge closely resembles one proposed in California, which has also raised major concerns from the solar industry and been criticized by the likes of Elon Musk, and has parallels to Massachusetts solar demand charges as well.
Although the "solar profile" of Nova Scotia and California is very different, with far more solar customers in that state, and in other provinces such as Saskatchewan, NDP criticism of 8% hikes has intensified affordability debates, Gregg said the fundamental issues are the same.
For those with a typical 10-kilowatt solar system, which generates around $1,800 of electricity a year, the new charge would mean those customers would be required to pay $960 back to NSP. That would roughly double the length of time it takes for those customers to pay off their investment for the panels.
David Brushett, chair of Solar Nova Scotia, said he relayed concerns from solar installers and others in the industry to Gregg on Monday.
Brushett said the year delay is a positive first step, but he is still calling on the province to take a strong stance against the application, which has led to customers cancelling their panel installations and companies considering layoffs.
"There's still an urgency to this situation that hasn't been addressed, and we need to kind of protect the industry," he said Tuesday.
NSP's original application proposed exempting net metering customers who enrolled before Feb. 1, 2022, from the charge for 25 years after they sign up. But any benefit would be lost if those customers sold their home, and the exemption wouldn't extend to the new buyers, said Brushett.
Carbon offsets missing from equation: industry Brushett said NSP "completely ignored" the fact that it's getting free carbon offset credits from homeowners who use solar energy under the provincial cap and trade program.
If the net metering system continues as is, NSP has said non-solar customers would pay about $55 million between now and 2030. That number assumes about 2,000 people sign up for net metering each year over the next nine years.
When asked whether those carbon emission credits were factored into the calculations for the proposed charge, Gregg said, "I don't believe in the current structure it is, but it's something that certainly we'd be open to hearing about."
Brushett said his group is finalizing a legal response to NSP's proposal and has already filed an official complaint against the company with the UARB.
Base charge on actual electrical output: customer At least one shareholder in NSP parent company Emera is considering selling his shares in response to the application.
Joe Hood, a shareholder from Middle Sackville, said the proposed charge won't apply to his existing 11.16-kilowatt solar system, but if it did, it would cost him $1,071 a year.
"I am offended that a company I would invest in would do this to the solar industry in Nova Scotia," he said.
According to his meter, Hood said he pushed 9,600 kilowatt hours of solar electricity to the grid last year— some only for a brief period, and all of which was used by his home by the end of the year.
Under the proposed charge, someone with one solar panel who goes away on vacation in the summer would push all their electricity to the grid, and be charged far less than someone with 10 panels who has used all their own power and hasn't pushed anything.
"Nova Scotia Power's argument is that it's an issue with the grid. Well, then it should be based on what touches the grid," Hood said.
Far from actually making the system fair for everyone, Hood said this charge places solar only in the hands of the super-rich or NSP, with projects like its community solar gardens in Amherst, N.S.
Green Party suggests legislation update Nova Scotia's Green Party also said Tuesday that Gregg's arguments of fairness are misleading, echoing earlier premier opposition to a 14% hike on rates.
The party is calling for an update to the Electricity Act that would "prevent penalizing any activity that helps Nova Scotia reach its emissions target," aligning with calls to make the electricity system more accountable to residents.
In its application, NSP has also asked to increase electricity rates for residential customers by at least 10 per cent over the next three years, amid debate that culminated in a 14% rate hike approval by regulators.
The company wants to maintain its nine per cent rate of return.
NSP expects to earn $153 million this year, $192 million in 2023, and $213 million in 2024 from its rate of return.
ITER Nuclear Fusion advances tokamak magnetic confinement, heating deuterium-tritium plasma with superconducting magnets, targeting net energy gain, tritium breeding, and steam-turbine power, while complementing laser inertial confinement milestones for grid-scale electricity and 2025 startup goals.
Key Points
ITER Nuclear Fusion is a tokamak project confining D-T plasma with magnets to achieve net energy gain and clean power.
✅ Tokamak magnetic confinement with high-temp superconducting coils
✅ Deuterium-tritium fuel cycle with on-site tritium breeding
✅ Targets net energy gain and grid-scale, low-carbon electricity
It sounds like the stuff of dreams: a virtually limitless source of energy that doesn’t produce greenhouse gases or radioactive waste. That’s the promise of nuclear fusion, often described as the holy grail of clean energy by proponents, which for decades has been nothing more than a fantasy due to insurmountable technical challenges. But things are heating up in what has turned into a race to create what amounts to an artificial sun here on Earth, one that can provide power for our kettles, cars and light bulbs.
Today’s nuclear power plants create electricity through nuclear fission, in which atoms are split, with next-gen nuclear power exploring smaller, cheaper, safer designs that remain distinct from fusion. Nuclear fusion however, involves combining atomic nuclei to release energy. It’s the same reaction that’s taking place at the Sun’s core. But overcoming the natural repulsion between atomic nuclei and maintaining the right conditions for fusion to occur isn’t straightforward. And doing so in a way that produces more energy than the reaction consumes has been beyond the grasp of the finest minds in physics for decades.
But perhaps not for much longer. Some major technical challenges have been overcome in the past few years and governments around the world have been pouring money into fusion power research as part of a broader green industrial revolution under way in several regions. There are also over 20 private ventures in the UK, US, Europe, China and Australia vying to be the first to make fusion energy production a reality.
“People are saying, ‘If it really is the ultimate solution, let’s find out whether it works or not,’” says Dr Tim Luce, head of science and operation at the International Thermonuclear Experimental Reactor (ITER), being built in southeast France. ITER is the biggest throw of the fusion dice yet.
Its $22bn (£15.9bn) build cost is being met by the governments of two-thirds of the world’s population, including the EU, the US, China and Russia, at a time when Europe is losing nuclear power and needs energy, and when it’s fired up in 2025 it’ll be the world’s largest fusion reactor. If it works, ITER will transform fusion power from being the stuff of dreams into a viable energy source.
Constructing a nuclear fusion reactor ITER will be a tokamak reactor – thought to be the best hope for fusion power. Inside a tokamak, a gas, often a hydrogen isotope called deuterium, is subjected to intense heat and pressure, forcing electrons out of the atoms. This creates a plasma – a superheated, ionised gas – that has to be contained by intense magnetic fields.
The containment is vital, as no material on Earth could withstand the intense heat (100,000,000°C and above) that the plasma has to reach so that fusion can begin. It’s close to 10 times the heat at the Sun’s core, and temperatures like that are needed in a tokamak because the gravitational pressure within the Sun can’t be recreated.
When atomic nuclei do start to fuse, vast amounts of energy are released. While the experimental reactors currently in operation release that energy as heat, in a fusion reactor power plant, the heat would be used to produce steam that would drive turbines to generate electricity, even as some envision nuclear beyond electricity for industrial heat and fuels.
Tokamaks aren’t the only fusion reactors being tried. Another type of reactor uses lasers to heat and compress a hydrogen fuel to initiate fusion. In August 2021, one such device at the National Ignition Facility, at the Lawrence Livermore National Laboratory in California, generated 1.35 megajoules of energy. This record-breaking figure brings fusion power a step closer to net energy gain, but most hopes are still pinned on tokamak reactors rather than lasers.
In June 2021, China’s Experimental Advanced Superconducting Tokamak (EAST) reactor maintained a plasma for 101 seconds at 120,000,000°C. Before that, the record was 20 seconds. Ultimately, a fusion reactor would need to sustain the plasma indefinitely – or at least for eight-hour ‘pulses’ during periods of peak electricity demand.
A real game-changer for tokamaks has been the magnets used to produce the magnetic field. “We know how to make magnets that generate a very high magnetic field from copper or other kinds of metal, but you would pay a fortune for the electricity. It wouldn’t be a net energy gain from the plant,” says Luce.
One route for nuclear fusion is to use atoms of deuterium and tritium, both isotopes of hydrogen. They fuse under incredible heat and pressure, and the resulting products release energy as heat
The solution is to use high-temperature, superconducting magnets made from superconducting wire, or ‘tape’, that has no electrical resistance. These magnets can create intense magnetic fields and don’t lose energy as heat.
“High temperature superconductivity has been known about for 35 years. But the manufacturing capability to make tape in the lengths that would be required to make a reasonable fusion coil has just recently been developed,” says Luce. One of ITER’s magnets, the central solenoid, will produce a field of 13 tesla – 280,000 times Earth’s magnetic field.
The inner walls of ITER’s vacuum vessel, where the fusion will occur, will be lined with beryllium, a metal that won’t contaminate the plasma much if they touch. At the bottom is the divertor that will keep the temperature inside the reactor under control.
“The heat load on the divertor can be as large as in a rocket nozzle,” says Luce. “Rocket nozzles work because you can get into orbit within minutes and in space it’s really cold.” In a fusion reactor, a divertor would need to withstand this heat indefinitely and at ITER they’ll be testing one made out of tungsten.
Meanwhile, in the US, the National Spherical Torus Experiment – Upgrade (NSTX-U) fusion reactor will be fired up in the autumn of 2022, while efforts in advanced fission such as a mini-reactor design are also progressing. One of its priorities will be to see whether lining the reactor with lithium helps to keep the plasma stable.
Choosing a fuel Instead of just using deuterium as the fusion fuel, ITER will use deuterium mixed with tritium, another hydrogen isotope. The deuterium-tritium blend offers the best chance of getting significantly more power out than is put in. Proponents of fusion power say one reason the technology is safe is that the fuel needs to be constantly fed into the reactor to keep fusion happening, making a runaway reaction impossible.
Deuterium can be extracted from seawater, so there’s a virtually limitless supply of it. But only 20kg of tritium are thought to exist worldwide, so fusion power plants will have to produce it (ITER will develop technology to ‘breed’ tritium). While some radioactive waste will be produced in a fusion plant, it’ll have a lifetime of around 100 years, rather than the thousands of years from fission.
At the time of writing in September, researchers at the Joint European Torus (JET) fusion reactor in Oxfordshire were due to start their deuterium-tritium fusion reactions. “JET will help ITER prepare a choice of machine parameters to optimise the fusion power,” says Dr Joelle Mailloux, one of the scientific programme leaders at JET. These parameters will include finding the best combination of deuterium and tritium, and establishing how the current is increased in the magnets before fusion starts.
The groundwork laid down at JET should accelerate ITER’s efforts to accomplish net energy gain. ITER will produce ‘first plasma’ in December 2025 and be cranked up to full power over the following decade. Its plasma temperature will reach 150,000,000°C and its target is to produce 500 megawatts of fusion power for every 50 megawatts of input heating power.
“If ITER is successful, it’ll eliminate most, if not all, doubts about the science and liberate money for technology development,” says Luce. That technology development will be demonstration fusion power plants that actually produce electricity, where advanced reactors can build on decades of expertise. “ITER is opening the door and saying, yeah, this works – the science is there.”
Ontario Electricity Grid Decarbonization outlines the IESO's net-zero pathway: $400B investment, nuclear expansion, renewables, hydrogen, storage, and demand management to double capacity by 2050 while initiating a 2027 natural gas moratorium.
Key Points
A 2050 plan to double capacity, retire gas, and invest $400B in nuclear, renewables, and storage for a net-zero grid.
✅ $400B over 25 years to meet net-zero electricity by 2050
✅ Capacity doubles to 88,000 MW; demand grows ~2% annually
✅ 2027 gas moratorium; build nuclear, renewables, storage
Ontario will need to spend $400 billion over the next 25 years in order to decarbonize the electricity grid and embrace clean power according to a new report by the province’s electricity system manager that’s now being considered by the Ford government.
The Independent System Electricity Operator (IESO) was tasked with laying out a path to reducing Ontario’s reliance on natural gas for electricity generation and what it would take to decarbonize the entire electricity grid by 2050.
Meeting the goal, the IESO concluded, will require an “aggressive” approach of doubling the electricity capacity in Ontario over the next two-and-a-half decades — from 42,000 MW to 88,000 MW — by investing in nuclear, hydrogen and wind and solar power while implementing conservation policies and managing demand.
“The process of fully eliminating emissions from the grid itself will be a significant and complex undertaking,” IESO president Lesley Gallinger said in a news release.
The road to decarbonization, the IESO said, begins with a moratorium on natural gas power generation starting in 2027 as long as the province has “sufficient, non-emitting supply” to meet the growing demands on the grid.
The approach, however, comes with significant risks.
The IESO said hydroelectric and nuclear facilities can take 10 to 15 years to build and if costs aren’t controlled the plan could drive up the price of clean electricity, turning homeowners and businesses away from electrification.
“Rapidly rising electricity costs could discourage electrification, stifle economic growth or hurt consumers with low incomes,” the report states.
The IESO said the province will need to take several “no regret” actions, including selecting sites and planning to construct new large-scale nuclear plants as well as hydroelectric and energy storage projects and expanding energy-efficiency programs beyond 2024.
READ MORE: Ontario faces calls to dramatically increase energy efficiency rebate programs
Ontario’s minister of energy didn’t immediately commit to implementing the recommendations, citing the need to consult with stakeholders first.
“I look forward to launching a consultation in the new year on next steps from today’s report, including the potential development of major nuclear, hydroelectric and transmissions projects,” Todd Smith said in a statement.
Currently, electricity demand is increasing by roughly two per cent per year, raising concerns Ontario could be short of electricity in the coming years as the manufacturing and transportation sectors electrify and as more sectors consider decarbonization.
At the same time, the province’s energy supply is facing “downward pressure” with the Pickering nuclear power plant slated to wind down operations and the Darlington nuclear generating station under active refurbishment.
To meet the energy need, the Ford government said it intended to extend the life of the Pickering plant until 2026.
READ MORE: Ontario planning to keep Pickering nuclear power station open until 2026
But to prepare for the increase, the Ontario government was told the province would also need to build new natural gas facilities to bridge Ontario’s electricity supply gap in the near term — a recommendation the Ford government agreed to.
The IESO said a request for proposals has been opened and the province is looking for host communities, with the expectation that existing facilities would be upgraded before projects on undeveloped land would be considered.
The IESO said the contract for any new facilities would expire in 2040, and all natural gas facilities would be retired in the 2040s.
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