In a big win for renewable energy developers in the state, the Public Service Commission has expanded the so-called Renewable Portfolio Standard that provides subsidies to clean energy projects.
The PSC issued an order allowing an additional $200 million to be spent for large-scale projects. That's on top of $95 million in subsidies that the New York State Energy Research and Development Authority said it recently awarded to five projects, including two in the capital region.
"It's a major jump," said NYSERDA spokesman Jeffrey Gordon. "It's a healthy increase."
The increase is needed because the state has also expanded its renewable energy goals. Former Gov. George Pataki first set the goal for the state to get 25 percent of its energy from renewable sources such as wind and hydro by 2013.
Gov. David Paterson has pushed the goal to 30 percent by 2015.
The commission's order follows approval of the increase by four of the commission's five members at its December meeting.
"We've been working toward this for months and months and months," said PSC spokesman James Denn.
Commissioner Robert Curry voted against the additional spending, saying it was unclear if the RPS, which will cost New Yorkers $2 billion over the next 15 years, is worth the money as currently structured.
"I respectfully dissent because the RPS as proposed is too costly to New York ratepayers and the commission has not taken sufficient time to adequately and completely debate the issues embedded in the expansion of the existing program," he wrote as part of the order.
NYSERDA collects money for the RPS through a special fee on utility bills. Collections totaled $83 million in 2009, with $100 million expected to be collected this year. The average homeowner pays roughly $3 a month in charges. The program has been responsible for adding 1,200 megawatts of new, clean electricity generation in the state.
The projects funded through NYSERDA's latest "solicitation" as it is called, include two hydro plants in the Capital Region owned by Brookfield Renewable Power of Canada that have expanded capacity.
Renewable Energy Security strengthens affordability and grid reliability through electrification, wind, and solar, reducing fossil fuel volatility exposed by the Ukraine crisis, aligning with IEA guidance and the Paris Agreement to deliver resilient, low-cost power.
Key Points
Renewable energy security is reliable, affordable power from electrification, wind and solar, cutting fossil fuel risk.
✅ Wind and solar now outcompete gas for new power capacity.
✅ Diversifies supply and reduces fossil price volatility.
✅ Requires grid flexibility, storage, and demand response.
Oil, gas, and coal have been the central pillar of the global energy system throughout the 20th century. And for decades, these fossil fuels have been closely associated with energy security.
The perception of energy security, however, is rapidly changing. Renewables form an increasing share of energy sectors worldwide as countries look to deliver on the Paris Agreement and mitigate the effects of climate change, with IEA clean energy investment now significantly outpacing fossil fuels. Moreover, Russia’s invasion of Ukraine has demonstrated how relying on fossil fuels for power, heating, and transport has left many countries vulnerable or energy insecure.
The International Energy Agency (IEA) defines energy security as “the uninterrupted availability of energy sources at an affordable price” (IEA, 2019a). This definition hardly describes today’s global energy situation, with the cancellation of natural gas deliveries and skyrocketing prices for oil and gas products, and with supply chain challenges in clean energy that also require attention. These circumstances have cascading effects on electricity prices in countries like the United Kingdom that rely heavily on natural gas to produce electricity. In Europe, energy insecurity has been even further amplified since the Russian corporation Gazprom recently cut off gas supplies to several countries.
As a result, energy security has gained new urgency in Canada and worldwide, creating opportunities in the global electricity market for Canada. Recent events provide a stark reminder of the volatility and potential vulnerability of global fossil fuel markets and supply chains. Even in Canada, as one of the largest producers of oil and gas in the world, the price of fuels depends on global and regional market forces rather than government policy or market design. Thus, the average monthly price for gasoline in Canada hit a record high of CAD 2.07 per litre in May 2022 (Figure 1), and natural gas prices surged to a record CAD 7.54 per MMBtu in May 2022 (Figure 2).
Energy price increases of this magnitude are more than enough to strain Canadian household budgets. But on top of that, oil and gas prices have accelerated inflation more broadly as it has become more expensive to produce, transport, and store goods, including food and other basic commodities (Global News, 2022).
Renewable Energy Is More Affordable
In contrast to oil and gas, renewable energy can reliably deliver affordable energy, as shown by falling wholesale electricity prices in markets with growing clean power. This is a unique and positive aspect of today’s energy crisis compared to historical crises: options for electrification and renewable-based electricity systems are both available and cost-effective.
For new power capacity, wind and solar are now cheaper than any other source, and wind power is making gains as a competitive source in Canada. According to Equinor (2022), wind and solar were already cheaper than gas-based power in 2020. This means that renewable energy was already the cheaper option for new power before the recent natural gas price spikes. As illustrated in Figure 3, the cost of new renewable energy has dropped so dramatically that, for many countries, it is cheaper to install new solar or wind infrastructure than to keep operating existing fossil fuel-based power plants (International Renewable Energy Agency, 2021). This means that replacing fossil-based electricity generation with renewables would save money and reduce emissions. Wind and solar prices are expected to continue their downward trends as more countries increase deployment and learn how to best integrate these sources into the grid.
Renewable Energy Is Reliable
To deliver on the uninterrupted availability side of the energy security equation, renewable power must remain reliable even as more variable energy sources, like wind and solar, are added to the system, and regional leaders such as the Prairie provinces will help anchor this transition. For Canada and other countries to achieve high energy security through electrification, grid system operations must be able to support this, and pathways to zero-emissions electricity by 2035 are feasible.
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.”
Muskrat Falls financial impact highlights a hydro megaproject's cost overruns, rate mitigation challenges, and inquiry findings in Newfoundland and Labrador, with power exports, Churchill River generation, and subsea cables shaping long-term viability.
Key Points
It refers to the project's burden on provincial finances, driven by cost overruns, rate hikes, and debt risks.
✅ Costs rose to $12.7B from $6.2B; inquiry cites suppressed risks.
✅ Rate mitigation needed to offset power bill shocks.
✅ Exports via subsea cables may improve long-term viability.
Newfoundland and Labrador's premier says the Muskrat Falls hydro megaproject is currently too much of a massive financial burden for him to be optimistic about its long-term potential.
"I am probably one of the most optimistic people in this room," Liberal Premier Dwight Ball told the inquiry into the project's runaway cost and scheduling issues, echoing challenges at Manitoba Hydro that have raised similar concerns.
"I believe the future is optimistic for Newfoundland Labrador, of course I do. But I'm not going to sit here today and say we have an optimistic future because of the Muskrat Falls project."
Ball, who was re-elected on May 16, has been critical of the project since he was opposition leader around the time it was sanctioned by the former Tory government.
He said Friday that despite his criticism of the Labrador dam, which has seen costs essentially double to more than $12.7 billion, he didn't set out to celebrate a failed project.
He said he still wants to see Muskrat Falls succeed someday through power sales outside the province, but there are immediate challenges -- including mitigating power-rate hikes once the dam starts providing full power and addressing winter reliability risks for households.
"We were told the project would be $6.2 billion, we're at $12.7 (billion). We were never told this project would be nearly 30 per cent of the net debt of this province just six, seven years later," the premier said.
"I wanted this to be successful, and in the long term I still want it to be successful. But we have to deal with the next 10 years."
The nearly complete dam will harness Labrador's lower Churchill River to provide electricity to the province as well as Nova Scotia and potentially beyond through subsea cables, while the legacy of Churchill Falls continues to shape regional power arrangements.
Ball's testimony wraps up a crucial phase of hearings in the extensive public inquiry.
The inquiry has heard from dozens of witnesses, with current and former politicians, bureaucrats, executives and consultants, amid debates over Quebec's electricity ambitions in the region, shedding long-demanded light on what went on behind closed doors that made the project go sideways.
Some witnesses have suggested that estimates were intentionally suppressed, and many high-ranking officials, including former premiers, have denied seeing key information about risk.
On Thursday, Ball testified to his shock when he began to understand the true financial state of the project after he was elected premier in 2015.
On Friday, Ball said he has more faith in future of the offshore oil and gas industry, and emerging options like small nuclear reactors, for example, than a mismanaged project that has put immense pressure on residents already struggling to make ends meet.
After his testimony, Ball said he takes some responsibility for a missed opportunity to mitigate methylmercury risks downstream from the dam through capping the reservoir, in parallel with debates over biomass power in electricity generation, something he had committed to doing before it is fully flooded this summer.
Still to come is a third phase of hearings on future best practices for issues like managing large-scale projects and independent electricity planning, two public feedback sessions and closing submissions from lawyers.
The final report from the inquiry is due before Dec. 31.
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.”
Near-Field Thermophotovoltaics captures radiated energy across a nanoscale gap, using thin-film photovoltaic cells and indium gallium arsenide to boost power density and efficiency, enabling compact Army portable power from emitters via radiative heat transfer.
Key Points
A nanoscale TPV method capturing near-field photons for higher power density at lower emitter temperatures.
✅ Nanoscale gap boosts radiative transfer and usable photon flux
✅ Thin-film InGaAs cells recycle sub-band-gap photons via reflector
✅ Achieved ~5 kW/m2 power density with higher efficiency
With the addition of sensors and enhanced communication tools, providing lightweight, portable power has become even more challenging, with concepts such as power from falling snow illustrating how diverse new energy-harvesting approaches are. Army-funded research demonstrated a new approach to turning thermal energy into electricity that could provide compact and efficient power for Soldiers on future battlefields.
Hot objects radiate light in the form of photons into their surroundings. The emitted photons can be captured by a photovoltaic cell and converted to useful electric energy. This approach to energy conversion is called far-field thermophotovoltaics, or FF-TPVs, and has been under development for many years; however, it suffers from low power density and therefore requires high operating temperatures of the emitter.
The research, conducted at the University of Michigan and published in Nature Communications, demonstrates a new approach, where the separation between the emitter and the photovoltaic cell is reduced to the nanoscale, enabling much greater power output than what is possible with FF-TPVs for the same emitter temperature.
This approach, which enables capture of energy that is otherwise trapped in the near-field of the emitter is called near-field thermophotovoltaics or NF-TPV and uses custom-built photovoltaic cells and emitter designs ideal for near-field operating conditions, alongside emerging smart solar inverters that help manage conversion and delivery.
This technique exhibited a power density almost an order of magnitude higher than that for the best-reported near-field-TPV systems, while also operating at six-times higher efficiency, paving the way for future near-field-TPV applications, including remote microgrid deployments in extreme environments, according to Dr. Edgar Meyhofer, professor of mechanical engineering, University of Michigan.
"The Army uses large amounts of power during deployments and battlefield operations and must be carried by the Soldier or a weight constrained system," said Dr. Mike Waits, U.S. Army Combat Capabilities Development Command's Army Research Laboratory. "If successful, in the future near-field-TPVs could serve as more compact and higher efficiency power sources for Soldiers as these devices can function at lower operating temperatures than conventional TPVs."
The efficiency of a TPV device is characterized by how much of the total energy transfer between the emitter and the photovoltaic cell is used to excite the electron-hole pairs in the photovoltaic cell, where insights from near-light-speed conduction research help contextualize performance limits in semiconductors. While increasing the temperature of the emitter increases the number of photons above the band-gap of the cell, the number of sub band-gap photons that can heat up the photovoltaic cell need to be minimized.
"This was achieved by fabricating thin-film TPV cells with ultra-flat surfaces, and with a metal back reflector," said Dr. Stephen Forrest, professor of electrical and computer engineering, University of Michigan. "The photons above the band-gap of the cell are efficiently absorbed in the micron-thick semiconductor, while those below the band-gap are reflected back to the silicon emitter and recycled."
The team grew thin-film indium gallium arsenide photovoltaic cells on thick semiconductor substrates, and then peeled off the very thin semiconductor active region of the cell and transferred it to a silicon substrate, informing potential interfaces with home battery systems for distributed use.
All these innovations in device design and experimental approach resulted in a novel near-field TPV system that could complement distributed resources in virtual power plants for resilient operations.
"The team has achieved a record ~5 kW/m2 power output, which is an order of magnitude larger than systems previously reported in the literature," said Dr. Pramod Reddy, professor of mechanical engineering, University of Michigan.
Researchers also performed state-of-the-art theoretical calculations to estimate the performance of the photovoltaic cell at each temperature and gap size, informing hybrid designs with backup fuel cell solutions that extend battery life, and showed good agreement between the experiments and computational predictions.
"This current demonstration meets theoretical predictions of radiative heat transfer at the nanoscale, and directly shows the potential for developing future near-field TPV devices for Army applications in power and energy, communication and sensors," said Dr. Pani Varanasi, program manager, DEVCOM ARL that funded this work.
EU Electricity Market Reform CFDs seek stable prices via contracts for difference, balancing renewables and nuclear, shielding consumers, and boosting competitiveness as France and Germany clash over scope, grid expansion, and hydrogen production.
Key Points
EU framework using contracts for difference to stabilize power prices, support renewables and nuclear, and protect users.
✅ Guarantees strike prices for new low-carbon generation
✅ Balances consumer protection with industrial competitiveness
Despite record temperatures this October, Europe is slowly shifting towards winter - its second since the Ukraine war started and prompted Russia to cut gas supplies to the continent amid an energy crisis that has reshaped policy.
After prices surged last winter, when gas and electricity bills “nearly doubled in all EU capitals”, the EU decided to take emergency measures to limit prices.
In March, the European Commission proposed a reform to revamp the electricity market “to boost renewables, better protect consumers and enhance industrial competitiveness”.
However, France and Germany are struggling to find a compromise as rolling back prices is tougher than it appears and the clock is ticking as European energy ministers prepare to meet on 17 October in Luxembourg.
The controversy around CFDs At the heart of the issue are contracts for difference (CFDs).
By providing a guaranteed price for electricity, CFDs aim to support investment in renewable energy projects.
France - having 56 nuclear reactors - is lobbying for nuclear energy to be included in the CFDs, but this has caught the withering eye of Germany.
Berlin suspects Paris of wanting an exception that would give its industry a competitive advantage and plead that it should only apply to new investments.
France wants ‘to regain control of the price’ The disagreement is at the heart of the bilateral talks in Hamburg, which started on Monday, between the French and German governments.
French President Emmanuel Macron promised “to regain control of the price of electricity, at the French and European level” and outlined a new pricing scheme in a speech at the end of September.
As gas electricity is much more expensive than nuclear electricity, France might be tempted to switch to a national system rather than a European one after a deal with EDF on prices to be more competitive economically.
However, France is "confident" that it will reach an agreement with Germany on electricity market reforms, Macron said on Friday.
Siding with France are other pro-nuclear countries such as Hungary, the Czech Republic and Poland, while Germany can count on the support of Austria, Luxembourg, Belgium and Italy amid opposition from nine EU countries to treating market reforms as a price fix.
But even if a last-minute agreement is reached, the two countries’ struggles over energy are creeping into all current European negotiations on the subject.
Germany wants a massive extension of electricity grids on the continent so that it can import energy; France is banking on energy sovereignty and national production.
France wants to be able to use nuclear energy to produce clean hydrogen, while Germany is reluctant, and so on.
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