Canada's electricity infrastructure needs an overhaul to meet the ever-increasing demands of a growing population, according to the president of the Canadian Electricity Association whose members make, move and sell electricity.
Pierre Guimond, in Victoria to address a Greater Victoria Chamber of Commerce luncheon, said the North American electricity sector "is being hobbled by a lack of infrastructure investment at a time when it is asked to take on a more expansive mandate."
"Right now energy is being discussed as the lifeblood of the economy... and the electricity grid that serves us so well was built for a [Canadian] population of about 20 million. We're now pushing something like 35 million," Guimond said. And the demand for electricity to fuel our gadgets, an Internet economy and lifestyle choices like electric cars is only going to grow.
"It's time to make some decisions that previous generations had to make," Guimond said.
"In other words: it's our time, it's our turn."
The bulk of the Canadian electricity grid, and in particular the B.C. portion, was built between 1950 and 1980, with very little of any consequence being added to that since.
To deal with increased demand, Guimond said since the early 1990s North America has engaged in electricity wheeling — moving electricity over long distances to suit demand — instead of building new generation.
"Over the last 20 years there's been very little building done as demand slowly caught up to oversupply," said Guimond with a nod to the engineers who originally overbuilt the system to accommodate expected growth. "That over-supply is now gone and we are now face to face with the prospect that we have to build to meet demand and build to strengthen the system because it's aging."
But that kind of infrastructure overhaul comes at a heavy price.
The CEA has been told by the International Energy Agency and Conference Board of Canada that this country will have to spend between $240 billion and $298 billion over the next 20 years to improve its electricity infrastructure to meet demand growth.
Guimond sees that price tag as an investment.
"Even with price hikes which are sure to happen [to pay for new infrastructure] electricity is still a bargain, and the price of electricity is still very much an investment in the future," he said.
"The aging infrastructure is an opportunity to renew, replace and build capacity to ensure reliability, supply and affordability," he said. "It's also an opportunity to strengthen our economy and if we act soon and act well we can really bolster the backbone of the Canadian economy."
Guimond acknowledged that emerging and alternative power supplies like solar, wind and wave play an important role in meeting new demand on the system, but he said the bottom line is countries must play to their strengths and Canada has water and gravity in its favour — that means turbines and dams.
"There's a place for everything on the grid, and we need everything, but big, strong turbines and big machines are still the backbone — they make solar and wind and other variable generation possible to integrate onto the grid," he said.
Guimond noted the entire system is in a transitional phase, including customers demanding more control over their use of power and how much they pay for it.
He said the much talked about smart grid, which begins with smart meters to help customers optimize their power use and how they pay for it, is a start to helping secure the reliability of supply.
But he remains adamant that changes like that are just a start, and that sooner rather than later this country is going to have to dig deep to pay for new generation.
East-West Transmission Project Ontario connects Thunder Bay to Wawa, facing OEB bidding, Hydro One vs NextBridge, First Nations consultation, environmental assessment, Pukaskwa National Park route, and reliability needs for Northwestern Ontario industry and communities.
Key Points
A 450 km Thunder Bay-Wawa power line proposal facing OEB bidding, Hydro One competition, and First Nations consultation.
✅ Competing bids: Hydro One vs NextBridge under OEB rules
✅ First Nations cite duty to consult and environmental review gaps
✅ Route debate: Pukaskwa Park vs bypass; jobs and reliability at stake
Leaders of six First Nations are urging the Ontario government to "clean up" the bureaucratic process that determines who will build an "urgently needed" high-capacity power transmission line to service northern Ontario.
The proposed 450 kilometre East-West Transmission Project is set to stretch from Thunder Bay to Wawa, providing much-needed electricity to northern Ontario. NextBridge Infrastructure, in partnership with Bamkushwada Limited Partnership (BLP) — an entity the First Nations created in order to become co-owners and active participants in the economic development of the line — have been the main proponents of the project since 2012 and were awarded the right to construct.
In 2018, Hydro One appealed to the previous Liberal government with a proposal to build the transmission line with lower maintenance costs. On Dec. 20, the Ontario Energy Board (OEB) issued a decision that said it will issue the contract to construct the project to the company with the lowest bid, even as a Manitoba Hydro line delay followed a board recommendation in a comparable case.
The transmission regime in Ontario allows competing bids at the beginning of a project to designate a transmitter, and then again at the end of the project to award leave to construct.
As a result, the Hydro One was permitted to submit a competing bid, five years after it was first proposed. The chiefs of the six First Nations say that will delay the project by two years, impede their land and violate their rights. The former Liberal government under which the project was initiated "left the door open" for competition to enter this late in the construction, according to the community leaders.
"The former government created this mess and Hydro One has taken advantage of this loophole," Fort William First Nation Chief Peter Collins said in a Queen's Park news conference on Thursday. "Hydro One is an interloper coming in at the last minute, trying taking over the project and all the hard work that has been done, without doing the work it needs to do."
Mess will explode, says chief
According to Collins, the Ontario Energy Board is likely to choose Hydro One's late submission in February, "causing this mess to explode." The electricity and distribution utility has not completed any of the legal requirements demanded by a project of this magnitude, Collins said, including extensive consultations with First Nations, such as oral traditional evidence hearings that inform regulators, and thorough environment assessments. He speculated that by ignoring these two things, even though in B.C. Ottawa did not oppose a Site C work halt pending a treaty rights challenge, Hydro One's bid will be the lowest cost.
"Hydro One's interference is a big problem," said Collins. He was flanked by the leaders of the Pic Mobert First Nation, Opwaaganasiniing (also known as the Red Rock Indian Band), Michipicoten, Biigtigong Nishnaabeg — or Pic River First Nation — and Pays Plat First Nation.
Collins also highlighted that Hydro One's proposed route for the transmission line will go through Pukaskwa National Park on which there are Aboriginal title claims, and noted that an opponent of the Site C dam has been sharing concerns with northerners, underscoring the need for meaningful engagement. NextBridge's proposal, Collins said, will go around the park.
If Hydro One is awarded the construction project, at risk, too, are as many as 1,000 job opportunities in northern Ontario (including the Ring of Fire) that are expected from NextBridge's proposal, as well as the "many millions" in contracting opportunities for the communities, Collins said.
"That companies such as Hydro One can do this and dissolve all that has been developed by NextBridge and our [partnership] and all the opportunities we have created will signal to ... everyone in Ontario that Ontario's not open for business, at least fair business," Collins said.
Ontario Energy Minister 'disappointed' by OEB's decision
In an email statement to National Observer, Energy Minister Greg Rickford's press secretary said the government acknowledged the concerns of the First Nations leaders, and is "disappointed that the OEB continues to stall on this important project."
"The East-West Tie project is a priority for Ontario because it is needed to provide a reliable and adequate supply of electricity to northwestern Ontario to support economic growth," she wrote.
In October, Rickford wrote to the OEB outlining his expectation that a prompt decision would be made through an efficient and fair process.
Despite the minister’s request, the OEB delayed a decision on this project in December — as in B.C., a utilities watchdog has pressed for answers on Site C dam stability — pushing the service date back to at least 2021. In 2017, NextBridge said that, pending OEB approval, it would start construction in 2018, with completion scheduled for 2020.
Without the transmission line, the community faces a higher likelihood of power outages and less reliable electricity overall.
"Our government takes the duty to consult seriously and it is committed to ensuring that all Indigenous communities are properly consulted and kept informed regardless of the result of the OEB process," Rickford's office's statement said.
In a letter sent to Premier Doug Ford, Rickford and to Environment Minister Rod Phillips, all members of the Bamkushwada Limited Partnership said they will be compelled to appeal the OEB's decision if the right to construct is given to Hydro One.
The entire situation, they wrote in their letter, is "an undeniable mess" that requires government intervention.
"If the Ontario government can correct this looming outcome, it is incumbent on the Ontario government to do so," they wrote, urging the government to "take all legal means to prevent the OEB from rendering an unconstitutional and unjust decision."
"Our First Nations and the north have waited five long years for this transmission project," Collins said. "Enough is enough."
California Governor Gavin Newsom vetoed a bill aimed at expanding load flexibility in state grid planning, citing conflicts with California’s resource adequacy framework and concerns over grid reliability and energy planning uncertainty.
Why has Newsom vetoed the Bill to Codify Load Flexibility?
Governor Gavin Newsom’s veto blocks legislation that would have required the California Energy Commission to incorporate load flexibility into the state’s energy planning and policy framework, a move that has stirred debate across the clean energy sector.
✅ Argues the bill conflicts with California’s existing Resource Adequacy system
✅ Draws backlash from clean energy and grid modernization advocates
✅ Exposes ongoing tension over how to manage renewable integration and demand response
California Governor Gavin Newsom has vetoed Assembly Bill 44, which would have required the California Energy Commission to evaluate and incorporate load management mechanisms into the state’s energy planning process. The move drew criticism from clean energy advocates who say it undermines efforts to strengthen grid reliability and reduce costs.
The bill directed the commission to adopt “upfront technical requirements and load modification protocols” that would allow load-serving entities to adjust their electrical demand forecasts. Proponents viewed this as a way to modernize California’s grid management, and to explore a revamp of electricity rates to help clean the grid, making it more responsive to demand fluctuations and renewable energy variability.
In his veto statement, Newsom said the bill was incompatible with existing energy planning frameworks, even as a looming electricity shortage remains a concern. “While I support expanding electric load flexibility, this bill does not align with the California Public Utility Commission’s Resource Adequacy framework,” he said. “As a result, the requirements of this bill would not improve electric grid reliability planning and could create uncertainty around energy resource planning and procurement processes.”
Newsom’s decision comes shortly after he signed a broad package of energy legislation that set the stage for a regional Western electricity market and extended the state’s cap-and-trade program. However, that legislative package did not include continued funding for several key grid reliability programs — including what advocates have called the world’s largest virtual power plant, a distributed network of connected devices that can balance electricity demand in real time.
Clean energy supporters saw AB 44 as a crucial step toward integrating these distributed energy resources into long-term grid planning. “With Assembly Bill 44 being vetoed, the state has missed a huge opportunity to advance common-sense policy that would have lowered costs, strengthened the grid, and unlocked the full potential of advanced energy,” said Edson Perez, California lead at Advanced Energy United.
Perez added that the setback increases pressure on lawmakers to take stronger action in the next legislative session. “The pressure is on next session to ensure that California is using all tools in its policy toolbox to build critically needed infrastructure, strengthen the grid, and bring costs down,” he said.
California’s growing use of demand response programs and virtual power plants has been central to its strategy for managing grid stress during heat waves and wildfire seasons. These systems allow utilities and customers to temporarily reduce or shift energy use, helping to prevent blackouts and reduce the need for fossil-fuel peaker plants during peak demand.
A recent report by the Brattle Group found that California’s taxpayer-funded virtual power plant could save ratepayers $206 million between 2025 and 2028 while reducing reliance on gas generation. The study, commissioned by Sunrun and Tesla Energy, highlighted the potential for flexible load management to improve both grid reliability and reduce costs, even as regulators weigh whether the state needs more power plants to ensure reliability.
Despite these findings, Newsom’s veto signals continued tension between state policymakers and clean energy advocates over how best to modernize California’s power grid. While the governor has prioritized large-scale renewable development and regional market integration, critics argue that California’s climate policy choices risk exacerbating reliability challenges and that failing to codify load flexibility could slow progress toward a more adaptive, resilient, and affordable clean energy future.
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.”
Hydro One Pandemic Relief Fund offers COVID-19 financial assistance, payment flexibility, and Winter Relief to Ontario electricity customers facing hardship, with disconnection protection and customer support to help manage bills during the health crisis.
Key Points
COVID-19 aid offering bill credits, payment flexibility, and disconnection protection for electricity customers.
✅ Financial assistance and bill credits for hardship cases
✅ Flexible payment plans and extended Winter Relief
✅ No-disconnect policy and dedicated customer support hours
We are pleased to announce a Pandemic Relief Fund to assist customers affected by the novel coronavirus (COVID-19). As part of our commitment to customers, we will offer financial assistance as well as increased payment flexibility to customers experiencing hardship. The fund is designed to support customers impacted by these events and those that may experience further impacts.
In addition to this, we've also extended our Winter Relief program, aligning with our ban on disconnections policy so no customer experiencing any hardship has to worry about potential disconnection.
We recognize that this is a difficult time for everyone and we want our customers to know that we’re here to support them. We hope this fund and the added measures, such as extended off-peak rates that help provide our customers peace of mind so they can concentrate on what matters most — keeping their loved ones safe.
If you are concerned about paying your bill, are experiencing hardship or have been impacted by the pandemic, including electricity relief announced by the province, we want to help you. Call us to discuss the fund and see what options are available for you.
CUSTOMER CONTACT CENTRE HOURS Call us at 1-888-664-9376
Monday to Friday from 7:30 a.m. to 8:00 p.m.
Saturdays from 9:00 a.m. to 3:00 p.m.
KEEPING ONTARIANS AND OUR ELECTRICITY SYSTEM SAFE We recognize the critical role we play in powering communities across the province and our support for the Province of Ontario during COVID-19. This is a responsibility to employees, customers, businesses and the people of Ontario that we take very seriously.
Since the novel coronavirus (COVID-19) outbreak began, Hydro One’s Pandemic Team along with our leadership, have been actively monitoring the issues to ensure we can continue to deliver the service Ontarians depend on while keeping our employees, customers and the public safe, even as there has been no cut in peak hydro rates yet for self-isolating customers across Ontario. While the risk in Ontario remains low, we believe we can best protect our people and our operations by taking proactive measures.
As information continues to evolve, our leadership team along with the Pandemic Planning Team and our Emergency Operations Centre are committed to maintaining business continuity while minimizing risk to employees and communities.
Over the days and weeks to come, we will work with the sector and government, which is preparing to extend disconnect moratoriums across the province, to enhance safety protocols and champion the needs of electricity customers in Ontario.
Alberta Electricity Price Surge reflects soaring wholesale rates, natural gas spikes, carbon tax pressures, and grid decarbonization challenges amid cold-weather demand, constrained supply, and Europe-style energy crisis impacts across the province.
Key Points
An exceptional jump in Alberta's power costs driven by gas price spikes, high demand, policy costs, and tight supply.
✅ Wholesale prices averaged $123/MWh in December
✅ Gas costs surged; supply constraints and outages
✅ Carbon tax and decarbonization policies raised costs
Albertans just endured the highest electricity prices in 21 years. Wholesale prices averaged $123 per megawatt-hour in December, more than triple the level from the previous year and highest for December since 2000.
The situation in Alberta mirrors the energy crisis striking Europe where electricity prices are also surging, largely due to a shocking five-fold increase in natural gas prices in 2021 compared to the prior year.
The situation should give pause to Albertans when they consider aggressive plans to “decarbonize” the electric grid, including proposals for a fully renewable grid by 2030 from some policymakers.
The explanation for skyrocketing energy prices is simple: increased demand (because of Calgary's frigid February demand and a slowly-reviving post-pandemic economy) coupled with constrained supply.
In the nitty gritty details, there are always particular transitory causes, such as disputes with Russian gas companies (in the case of Europe) or plant outages (in the case of Alberta).
But beyond these fleeting factors, there are more permanent systemic constraints on natural gas (and even more so, coal-fired) power plants.
I refer of course to the climate change policies of the Trudeau government at the federal level and some of the more aggressive provincial governments, which have notable implications for electricity grids across Canada.
The most obvious example is the carbon tax, the repeal of which Premier Jason Kenney made a staple of his government.
Putting aside the constitutional issues (on which the Supreme Court ruled in March of last year that the federal government could impose a carbon tax on Alberta), the obvious economic impact will be to make carbon-sourced electricity more expensive.
This isn’t a bug or undesired side-effect, it’s the explicit purpose of a carbon tax.
Right now, the federal carbon tax is $40 per tonne, is scheduled to increase to $50 in April, and will ultimately max out at a whopping $170 per tonne in 2030.
Again, the conscious rationale of the tax, aligned with goals for cleaning up Canada's electricity, is to make coal, oil and natural gas more expensive to induce consumers and businesses to use alternative energy sources.
As Albertans experience sticker shock this winter, they should ask themselves — do we want the government intentionally making electricity and heating oil more expensive?
Of course, the proponent of a carbon tax (and other measures designed to shift Canadians away from carbon-based fuels) would respond that it’s a necessary measure in the fight against climate change, and that Canada will need more electricity to hit net-zero according to the IEA.
Yet the reality is that Canada is a bit player on the world stage when it comes to carbon dioxide, responsible for only 1.5% of global emissions (as of 2018).
As reported at this “climate tracker” website, if we look at the actual policies put in place by governments around the world, they’re collectively on track for the Earth to warm 2.7 degrees Celsius by 2100, far above the official target codified in the Paris Agreement.
Canadians can’t do much to alter the global temperature, but federal and provincial governments can make energy more expensive if policymakers so choose, and large-scale electrification could be costly—the Canadian Gas Association warns of $1.4 trillion— if pursued rapidly.
As renewable technologies become more reliable and affordable, business and consumers will naturally adopt them; it didn’t take a “manure tax” to force people to use cars rather than horses.
As official policy continues to make electricity more expensive, Albertans should ask if this approach is really worth it, or whether options like bridging the Alberta-B.C. electricity gap could better balance costs.
Robert P. Murphy is a senior fellow at the Fraser Institute.
Cyprus Electricity Interconnectors link the island to the EU grid via EuroAsia and EuroAfrica projects, enabling renewable energy trade, subsea transmission, market liberalization, and stronger energy security and diplomacy across the region.
Key Points
Subsea links connecting Cyprus to Greece, Israel and Egypt for EU grid integration, renewable trade and energy security.
✅ Connects EU, Israel, Egypt via EuroAsia and EuroAfrica
✅ Enables renewables integration and market liberalization
✅ Strengthens energy security, investment, and diplomacy
Electricity interconnectors bridging Cyprus with the broader geographical region, mirroring projects like the Ireland-France grid link already underway in Europe, are crucial for its diplomacy while improving its game to become a clean energy hub.
In an interview with Phileleftheros daily, Andreas Poullikkas, chairman of the Cyprus Energy Regulatory Authority (CERA), said electricity cables such as the EuroAsia Interconnector and the EuroAfrica Interconnector, could turn the island into an energy hub, creating investment opportunities.
“Cyprus, with proper planning, can make the most of its energy potential, turning Cyprus into an electricity producer-state and hub by establishing electrical interconnections, such as the EuroAsia Interconnector and the EuroAfrica Interconnector,” said Poullikkas.
He said these electricity interconnectors, “will enable the island to become a hub for electricity transmission between the European Union, Israel and Egypt, with developments such as the Israel Electric Corporation settlement highlighting regional dynamics, while increasing our energy security”.
Poullikkas argued it will have beneficial consequences in shaping healthy conditions for liberalising the country’s electricity market and economy, facilitating the production of electricity with Renewable Energy Sources and supporting broader efforts like the UK grid transformation toward net zero.
“Electricity interconnections are an excellent opportunity for greater business flexibility in Cyprus, ushering new investment opportunities, as seen with the Lake Erie Connector investment across North America, either in electricity generation or other sectors. Especially at a time when any investment or financial opportunity is welcomed.”
He said Cyprus’ energy resources are a combination of hydrocarbon deposits and renewable energy sources, such as solar.
This combination offers the country a comparative advantage in the energy sector.
Cyprus can take advantage of the development of alternative supply routes of the EU, as more links such as new UK interconnectors come online.
Poullikkas argued that as energy networks are developing rapidly throughout the bloc, serving the ever-increasing needs for electricity, and aligning with the global energy interconnection vision highlighted in recent assessments, the need to connect Cyprus with its wider geographical area is a matter of urgency.
He argues the development of important energy infrastructure, especially electricity interconnections, is an important catalyst in the implementation of Cyprus goals, while recognising how rule changes like Australia's big battery market shift can affect storage strategies.
“It should also be a national political priority, as this will help strengthen diplomatic relations,” added Poullikkas.
Implementing the electricity interconnectors between Israel, Cyprus and Greece through Crete and Attica (EuroAsia Interconnector) has been delayed by two years.
He said the delay was brought about after Greece decided to separate the Crete-Attica section of the interconnection and treat as a national project.
Poullikkas stressed the Greek authorities are committed to ensuring the connection of Cyprus with the electricity market of the EU.
“All the required permits have been obtained from the competent authorities in Cyprus and upon the completion of the procedures with the preferred manufacturers, construction of the Cyprus-Crete electrical interconnection will begin before the end of this year. Based on current data, the entire interconnection is expected to be implemented in 2023”.
“The EuroAfrica Interconnector is in the pre-works stage, all project implementation studies have already been completed and submitted to the competent authorities, including cost and benefit studies”.
EuroAsia Interconnector is a leading EU project of common interest (PCI), also labelled as an “electricity highway” by the European Commission.
It connects the national grids of Israel, Cyprus and Greece, creating a reliable energy bridge between the continents of Asia and Europe allowing bi-directional transmission of electricity.
The cost of the entire subsea cable system, at 1,208km, the longest in the world and the deepest at 3,000m below sea level, is estimated at €2.5 bln.
Construction costs for the first phase of the Egypt-Cyprus interconnection (EuroAfrica) with a Stage 1 transmission capacity of 1,000MW is estimated at €1bln.
The Cyprus-Greece (Crete) interconnection, as well as the Egypt-Cyprus electricity interconnector, will both be commissioned by December 2023.
