Areva's troublesome EPR reactor project in Finland received a clean bill of health after welding work overseen by Bouygues, the French nuclear group's subcontractor, was called into question.
Petteri Tiippana, assistant director of STUK, the Finnish nuclear safety authority, said that a government-commissioned inquiry into quality and safety allegations made by the environmental lobby group Greenpeace had found no evidence of transgressions.
On the 35 load-bearing welded joints inspected by STUK, "the welding procedures, the qualification of the welders, the welds themselves are well done", he said.
On the thousands of non-load bearing joints which are not inspected by STUK, "the welds were made by qualified welders and systematic inspections were made", he went on to point out.
Mr Tiippana also refuted allegations made in a television documentary broadcast that Bouygues employees had been banned from discussing safety concerns.
The inquiry found no such rules and STUK inspectors had not had any problems discussing safety with them. However, workers had to seek approval before talking to anyone off-site, such as journalists.
STUK said it had been convinced by the Bouygues project manager "that all employees are obliged to report... any safety-related deviances.
"Deviances are documented and fixed according to the quality system."
STUK said it would check this documentation.
Bouygues said that the issue was now closed and it would not comment further.
Nonetheless, the controversy was taken seriously by the French construction group, which this summer was criticized along with power utility EDF for organisation of work on concrete reinforcement in a EPR reactor which is being built in Normandy.
Areva said it was delighted with STUK's public statement as "delivering a safe EPR reactor is an absolute priority for us".
Finland's Olkiluoto3 EPR reactor is being built by a consortium led by Areva.
It is the world's first so-called third-generation nuclear reactor, an Areva design and the group's first turnkey project, has been fraught with problems and is currently running two years late and at least €1bn ($1.47bn) over budget.
Canada Clean Electricity Regulations allow flexible, technology-neutral pathways to a 2035 net-zero grid, permitting limited natural gas with carbon capture, strict emissions standards, and exemptions for emergencies and peak demand across provinces and territories.
Key Points
Federal draft rules for a 2035 net-zero grid, allowing limited gas with CCS under strict performance and compliance standards.
✅ Performance cap: 30 tCO2 per GWh annually for gas plants
✅ CCS must sequester 95% of emissions to comply
✅ Emergency and peak demand exemptions permitted
After facing pushback from Alberta and Saskatchewan, and amid looming power challenges nationwide, Canada's draft net-zero electricity regulations — released today — will permit some natural gas power generation.
Environment Minister Steven Guilbeault released Ottawa's proposed Clean Electricity Regulations on Thursday.
Provinces and territories will have a minimum 75-day window to comment on the draft regulations. The final rules are intended to pave the way to a net-zero power grid in Canada, aligning with 2035 clean electricity goals established nationally.
Calling the regulations "technology neutral," Guilbeault said the federal government believes there's enough flexibility to accommodate the different energy needs of Canada's diverse provinces and territories, including how Ontario is embracing clean power in its planning.
"What we're talking about is not a fossil fuel-free grid by 2035; it's a net zero grid by 2035," Guilbeault said.
"We understand there will be some fossil fuels remaining … but we're working to minimize those, and the fossil fuels that will be used in 2035 will have to comply with rigorous environmental and emission standards," he added.
Some analysts argue that scrapping coal-fired electricity can be costly and ineffective, underscoring the trade-offs in transition planning.
While non-emitting sources of electricity — hydroelectricity, wind and solar and nuclear — should not have any issues complying with the regulations, natural gas plants will have to meet specific criteria.
Those operations, the government said, will need to emit the equivalent of 30 tonnes of carbon dioxide per gigawatt hour or less annually to help balance demand and emissions across the grid.
Federal officials said existing natural gas power plants could comply with that performance standard with the help of carbon capture and storage systems, which would be required to sequester 95 per cent of their emissions.
"In other words, it's achievable, and it is achievable by existing technology," said a government official speaking to reporters Thursday on background and not for attribution.
The regulations will also allow a certain level of natural gas power production without the need to capture emissions. Capturing emissions will be exempted during emergencies and peak periods when renewables cannot keep up with demand.
Some newer plants might not have to comply with the rules until the 2040s, because the regulations apply to plants 20 years after they are commissioned, which dovetails with net-zero by 2050 commitments from electricity associations.
The two-decade grace period does not apply to plants that open after the regulations are expected to be finalized in 2025.
BC Hydro Site C and Clean Energy Policy shapes B.C.'s power mix, affecting run-of-river hydro, net metering for rooftop solar, independent power producers, and surplus capacity forecasts tied to LNG Canada demand.
Key Points
BC Hydro's strategy centers on Site C, limiting new run-of-river projects and tightening net metering amid surplus power
✅ Site C adds long-term capacity with lower projected rates.
✅ Net metering limits deter oversized rooftop solar.
Innergex Renewable Energy Inc. is celebrating the official commissioning today of what may be the last large run-of-river hydro project in B.C. for years to come.
The project – two new generating stations on the Upper Lillooet River and Boulder Creek in the Pemberton Valley – actually began producing power in 2017, but the official commissioning was delayed until Friday September 14.
Innergex, which earlier this year bought out Vancouver’s Alterra Power, invested $491 million in the two run-of-river hydro-electric projects, which have a generating capacity of 106 megawatts of power. The project has the generating capacity to power 39,000 homes.
The commissioning happened to coincide with an address by BC Hydro CEO Chris O’Riley to the Greater Vancouver Board of Trade Friday, in which he provided an update on the progress of the $10.7-billion Site C dam project.
That project has put an end, for the foreseeable future, of any major new run-of-river projects like the Innergex project in Pemberton.
BC Hydro expects the new dam to produce a surplus of power when it is commissioned in November 2024, so no new clean energy power calls are expected for years to come.
Independent power producers aren’t the only ones who have seen a decline in opportunities to make money in B.C. providing renewable power, as the Siwash Creek project shows. So will homeowners who over-build their own solar power systems, in an attempt to make money from power sales.
There are about 1,300 homeowners in B.C. with rooftop solar systems, and when they produce surplus power, they can sell it to BC Hydro.
BC Hydro is amending the net metering program to discourage homeowners from over-building. In some cases, some howeowners have been generating 40% to 50% more power than they need.
“We were getting installations that were massively over-sized for their load, and selling this big quantity of power to us,” O’Riley said. “And that was never the idea of the program.”
Going forward, BC Hydro plans to place limits on how much power a homeowner can sell to BC Hydro.
BC Hydro has been criticized for building Site C when the demand for power has been generally flat, and reliance on out-of-province electricity has drawn scrutiny. But O’Riley said the dam isn’t being built for today’s generation, but the next.
“We’re not building Site C for today,” he said. “We have an energy surplus for the short term. We’re not even building it for 2024. We’re building it for the next 100 years.”
O’Riley acknowledged Site C dam has been a contentious and “extremely challenging” project. It has faced numerous court challenges, a late-stage review by the BC Utilities Commission, cost overruns, geotechnical problems and a dispute with the main contractors.
In a separate case, the province was ordered to pay $10 million over the denial of a Squamish power project, highlighting broader legal risk.
But those issues have been resolved, O’Riley said, and the project is back on track with a new construction schedule.
“As we move forward, we have a responsibility to deliver a project on time and against the new revised budget, and I’m confident the changes we’ve made are set up to do that,” O’Riley said.
Currently, there are about 3,300 workers employed on the dam project.
Despite criticisms that BC Hydro is investing in a legacy mega-project at a time when cost of wind and solar have been falling, O’Riley insisted that Site C was the best and lowest cost option.
“First, it’s the lowest cost option,” he said. “We expect over the first 20 years of Site C’s operating life, our customers will see rates 7% to 10% below what it would otherwise be using the alternatives.”
BC Hydro missed a critical window to divert the Peace River, something that can only be done in September, during lower river flows. That added a full year’s delay to the project.
O’Riley said BC Hydro had built in a one-year contingency into the project, so he expects the project can still be completed by 2024 – the original in-service target date. But the delay will add more than $2 billion to the last budget estimate, boosting the estimated capital cost from $8.3 billion to $10.7 billion.
Meeting the 2024 in-service target date could be important, if Royal Dutch Shell and its consortium partners make a final investment decision this year on the $40 billion LNG Canada project.
That project also has a completion target date of 2024, and would be a major new industrial customer with a substantial power draw for operations.
“If they make a decision to go forward, they will be a very big customer of BC Hydro,” O’Riley told Business in Vancouver. “They would be in our top three or four biggest customers.”
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.”
ACCC energy underwriting guarantee proposes government-backed certainty for new generation, cutting electricity prices and supporting gas, pumped hydro, renewables, batteries, and potentially coal-fired power, addressing market failure without direct subsidies.
Key Points
A tech-neutral, government-backed plan underwriting new generation revenue to increase certainty and cut power prices.
✅ Government guarantee provides a revenue floor for new generators.
✅ Intended to reduce bills by up to $400 and address market failure.
Australian Taxpayers won't directly fund any new power plants despite some Coalition MPs seizing on a new report to call for a coal-fired power station.
The Australian Competition and Consumer Commission recommended the government give financial certainty to new power plants, guaranteeing energy will be bought at a cheap price if it can't be sold, as part of an electricity market plan to avoid threats to supply.
It's part of a bid to cut up to $400 a year from average household power prices.
Prime Minister Malcolm Turnbull said the finance proposal had merit, but he ruled out directly funding specific types of power generation.
"We are not in the business of subsidising one technology or another," he told reporters in Queensland today.
"We've done enough of that. Frankly, there's been too much of that."
Renewable subsidies, designed in the 1990s to make solar and wind technology more affordable, have worked and will end in 2020.
Some Coalition MPs claim the ACCC's recommendation to underwrite power generation is vindication for their push to build new coal-fired power plants.
But ACCC chair Rod Sims said no companies had proposed building new coal plants - instead they're trying to build new gas projects, pumped hydro or renewable projects.
Opposition Leader Bill Shorten said Mr Turnbull was offering solutions years away, having overseen a rise in power prices over the past year.
"You don't just go down to K-Mart and get a coal-fired power station off the shelf," Mr Shorten told reporters, admitting he had not read the ACCC report.
Energy Minister Josh Frydenberg said the recommendation to underwrite new power generators had a lot of merit, as it would address a market failure highlighted by AEMO warnings about reduced reserves.
"What they're saying is the government needs to step in here to provide some sort of assurance," Mr Frydenberg told 9NEWS today.
He said that could include coal, gas, renewable energy or battery storage.
Deputy Nationals leader Bridget McKenzie said science should determine which technology would get the best outcomes for power bills, with a scrapping coal report suggesting it can be costly.
Mr Turnbull said there was strong support for the vast majority of the ACCC's 56 recommendations, but the government would carefully consider the report, which sets out a blueprint to cut electricity bills by 25 percent.
Acting Greens leader Adam Bandt said Australia should exit coal-fired power in favour of renewable energy to cut pollution.
In contrast, Canada has seen the Stop the Shock campaign advocate a return to coal power in some provinces.
The Australian Energy Council, which represents 21 major energy companies, said the government should consult on changes to avoid "unintended consequences".
Philippsburg Demolition Delay: EnBW postpones controlled cooling-tower blasts amid the coronavirus pandemic, affecting decommissioning timelines in Baden-Wurttemberg and grid expansion for a transformer station to route renewable power and secure supply in southern Germany.
Key Points
EnBW's COVID-19 delay of Philippsburg cooling-tower blasts, affecting decommissioning and grid plans.
✅ Controlled detonation shifted to mid-May at earliest
✅ Demolition links to transformer station for north-south grid
✅ Supports security of supply in southern Germany
German energy company EnBW said the coronavirus outbreak has impacted plans to dismantle its Philippsburg nuclear power plant in Baden-Wurttemberg, southwest Germany, amid plans to phase out coal and nuclear nationally.
The controlled detonation of Phillipsburg's cooling towers will now take place in mid-May at the earliest, subject to coordination as Germany debates whether to reconsider its nuclear phaseout in light of supply needs.
However, EnBW said the exact demolition date depends on many factors - including the further development in the coronavirus pandemic and ongoing climate policy debates about energy choices.
Philippsburg 2, a 1402MWe pressurised water reactor unit permanently shut down on 31 December 2019, as part of Germany's broader effort to shut down its remaining reactors over time.
At the end of 2019, the Ministry of the Environment gave basic approval for decommissioning and dismantling of unit 2 of the Philippsburg nuclear power plant, inluding explosive demolition of the colling towers. Since then EnBW has worked intensively on getting all the necessary formal steps on the way and performing technical and logistical preparatory work, even as discussions about a potential nuclear resurgence continue nationwide.
“The demolition of the cooling towers is directly related to future security of supply in southern Germany. We therefore feel obliged to drive this project forward," said Jörg Michels head of the EnBW nuclear power division.
The timely removal of the cooling towers is important as the area currently occupied by nuclear plant components is needed for a transformer station for long-distance power lines, an issue underscored during the energy crisis when Germany temporarily extended nuclear power to bolster supply. These will transport electricity from renewable sources in the north to industrial centres in the south.
As of early 2020, there six nuclear reactors in operation in Germany, even as the country turned its back on nuclear in subsequent years. According to research institute Fraunhofer ISE, nuclear power provided about 14% of Germany's net electricity in 2019, less than half of the figure for 2000.
Labrador Island Link Reliability faces scrutiny as Nalcor Energy and General Electric address software issues; Liberty Consulting warns of Holyrood risks, winter outages, grid stability concerns, and PUB oversight for Newfoundland and Labrador.
Key Points
It is the expected dependability of the link this winter, currently uncertain due to GE software and Holyrood risks.
✅ GE software delays may hinder reliable in-service by mid-November.
✅ PUB directs Hydro to plan contingencies and improve assets.
An independent consultant is questioning if the brand new Labrador Island link can be counted on to supply power to Newfoundland this coming winter.
In June, Nalcor Energy confirmed it had successfully sent power from Churchill Falls to the Avalon Peninsula through its more than 1500-kilometre link, but now the Liberty Consulting Group says it doesn't expect the link will be up and running consistently this winter.
"What we have learned supports a conclusion that the Labrador Island Link is unlikely to be reliably in commercial operation at the start of the winter," says the report dated Aug. 30, 2018.
The link relies on software provided by General Electric but Liberty says there are lingering questions about GE's ability to ensure the necessary software will be in place this fall.
"At an August meeting, company representatives did not express confidence in GE's ability to meet an in-service date for the Labrador Island Link of mid-November," says the report.
Liberty also says testing the link for a brief period this spring and fall doesn't demonstrate long-term reliability.
"The link will remain prone to the uncertainties any new major facility faces early in its operating life, especially one involving technology new to the operating company," according to the report.
Holyrood trouble
The report goes on to say island residents should also be worried about the reliability of the troubled Holyrood facility — a facility that's important when demand for energy is high during winter months.
Liberty says "poor performance at the Holyrood thermal generating station increases the risk of outages considerably."
The group's report concludes the deteriorating condition of Holyrood is a major threat to the island's power supply and Liberty says that threat "could produce very severe consequences when the Labrador Island Link is unavailable."
The consultant says questions about the Labrador Island Link's readiness combined with concerns about the reliability of Holyrood may mean power outages, and for vulnerable customers, debates over hydro disconnections policies often intensify during winter.
"This all suggests that, for at least part of this winter, the island interconnected system may be at the mercy of the weather, where severe events can test utilities' storm response efforts further."
The consultant's report also includes five recommendations to the PUB, reflecting the kind of focused nuclear alert investigation follow-up seen elsewhere.
In essence, Liberty is calling for the board to direct Newfoundland and Labrador Hydro to make plans for the possibility that the link won't be available this winter. It's also calling on hydro to do more to improve the reliability of its other assets, such as Holyrood, as some operators have even contemplated locking down key staff to maintain operations during crises.
Response to Liberty's report
Nalcor CEO Stan Marshall defended the Crown corporation's winter preparedness in an email statement to CBC.
"The right level of planning and investment has been made for our existing equipment so we can continue to meet all of our customer electricity needs for this coming winter season," he wrote.
Regarding the Labrador Island Link, Marshall called for patience.
"This is new technology for our province and integrating the new transmission assets into our current electricity system is complex work that takes time," he said.
There is also a more detailed response from Newfoundland and Labrador Hydro which was sent to the province's Public Utiltiies Board.
Hydro says it will keep testing the Labrador Island Link and increasing the megawatts that are wheeled through it. It also says in October it will begin to give the PUB regular reports on the link's anticipated in-service date.
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