The power structure in Canada is changing — not the government, but the country's electricity infrastructure.
By 2020, where electricity comes from and how it gets to your door will have undergone an unprecedented overhaul. Windmills will dot the landscapes of the Great Lakes and remote B.C. Smoke from coal plants will be buried in Saskatchewan and Alberta. A massive underwater cable will feed voltage from Labrador to as far away as New England.
It's all part of a complex series of initiatives that will reformulate everything from who produces the energy that powers your stove or dishwasher, to how they produce it, to your own power consumption habits and how much you'll pay each month.
"Electricity is one of the basic fuels of the economy. Not much happens without it," says Pierre Guimond, CEO of the Canadian Electricity Association, an industry group. "So getting the basics done correctly — yeah, we've got a lot on our plates."
CBC News has analyzed hundreds of studies, contracts, reports, strategy documents, maps and statistics about the country's electrical future. Many of the details have never before been gathered and shared with the public. We've produced the first map, for example, of every major generating station that's operating in Canada today or forecast to start up by 2020. And we've calculated what it will likely cost for your electricity, based on each province's current power generation strategy — and the surprising array of companies you'll be buying it from.
To the tens of millions of North Americans who spent many hours in the dark during the blackout of 2003, the question lingers: Do we generate enough electricity to meet the growing needs of homes and businesses, and do we have a robust enough grid to stave off future outages?
In 2003, Ontario, Canada's second-largest powerhouse after Quebec, was on the brink. Its independent grid operator made doomful pronouncements about shortages, and Ontario had to import a sizeable chunk of its energy from the United States.
More recently, British Columbia has become a net importer of current from south of the border. Alberta, Nova Scotia and Saskatchewan also rely on foreign sources.
The outlook has improved, but there's still cause for caution.
Ontario now sends $400 million in electricity to the U.S. each year, while B.C. is aiming to be self-sufficient by 2016. Alberta has seen a torrid pace of generator construction, although a March report by Canaccord Genuity predicts the province's power consumption is expected to rise by an estimated 4 per cent a year, putting pressure on the amount of power available and driving prices up. On the East Coast, the hydroelectric development of the Lower Churchill River will eventually bring online enough capacity to power any one of the Atlantic provinces in its entirety.
Overall, the country's system still needs massive cash infusions.
The International Energy Agency estimates Canada will require $10 billion a year in investments in its electrical infrastructure from now until 2030. A little over half of that will go towards generation and the rest to improve the bulk transmission grid and the more modest power lines that distribute electricity to homes.
The most recent assessment from the North American Electric Reliability Corp. – which is authorized by both the Canadian and U.S. governments to ensure the adequacy of the grids in both countries and ensures there's an adequate power supply — isn't overly rosy, either. NERC says that as of 2012, Quebec "needs additional resources" on its generation side, while B.C. and Alberta still need to "accelerate … resource development" to meet their needs for 2020. Ontario, despite its scheme to bring hundreds of small-scale generation online through guaranteed rate offers, is predicted to be a "tight area."
German Energy Price Brakes harness price signals in a market-based policy, cutting gas consumption, preserving industrial output, and supporting CO2 reduction, showcasing Germany's resilience and adaptation while protecting households and businesses across Europe.
Key Points
Fixed-amount subsidies preserving price signals to curb gas use, shield consumers, and sustain industrial output.
✅ Maintains incentives via market-based price signals
✅ Cuts gas consumption without distorting EU markets
✅ Protects households and industry while curbing CO2
German industry and society are once again proving much more resilient and adaptable than certain people feared. Horror scenarios of a dangerous energy rationing or a massive slump in our economy have often been bandied about. But we are nowhere near that. With a challenging year just behind us, this is good news — not only for Germany, but also for Europe, where France-Germany energy cooperation has strengthened solidarity.
Companies and households reacted swiftly to the sharp increases in energy prices, in line with momentum in the global energy transition seen across markets. They installed more efficient heating or production facilities, switched to alternatives and imported intermediate products. The results are encouraging: German households and businesses have reduced gas consumption significantly, despite recent cold weather. From the start of the war in Ukraine to mid-December industrial gas consumption in Germany was (temperature-adjusted) around 20 per cent lower than the average level for the preceding three years. Even if some firms have cut back production, especially in energy-intensive sectors, industrial output as a whole has only fallen by about 1 per cent since the start of 2022. Added to this, in a survey released by the Ifo institute in November, over a third of German companies saw the potential to reduce gas consumption further without endangering output.
Instead of imposing excessive laws and regulations, we have relied on price signals and the prudence of market participants to create the right incentives and reduce gas consumption, as falling costs like record-low solar power prices continue to reinforce those signals across sectors.
We will follow this approach in coming months, when energy savings will remain important, even as the EU electricity outlook anticipates sharply higher demand by 2050. Our latest relief measures will not distort price signals. To this end, the Bundestag approved gas and electricity price brakes in its final session in 2022. They are designed to function without any intervention in markets or prices. This system will pay out a fixed amount relative to previous years’ consumption and the current difference to a reference price — regardless of current consumption.
Energy price brakes are the main component of Germany’s “protective shield”, which makes up to €200bn available for measures in 2022 to 2024. Seen in relation to the German economy’s size, its past heavy reliance on Russian energy imports and the fact that the measures will expire in 2024, these are balanced and expedient mechanisms. In contrast to instruments used in other countries, our new arrangements will not affect the price formation process driven by supply and demand, or on incentives to save gas. Companies and households will continue to save the full market price when they reduce consumption by a unit of gas or electricity. In this way, the price brakes also avoid the creation of additional demand for gas at the expense of consumers in other European countries, even as Europe’s Big Oil turning electric signals broader structural shifts in energy markets. No one need fear that competition will be distorted or that gas will be bought up. Indeed, a recent IMF working paper on cushioning the impact of high energy prices on households explicitly praises the German energy price brakes.
Current developments confirm the effectiveness of a market-based approach — and show that we should also rely on price signals when it comes to reducing CO₂ emissions, as suggested by IEA CO2 trends in recent years. Last year, households and companies had only a few weeks to adapt, yet we have already seen a strong response. The effect of CO₂ prices can be even stronger, as adaptation is possible over a much longer time and they additionally affect expectations and long-term decisions. Regulatory interventions and subsidy schemes, even if well targeted, cannot compete with market co-ordination and incentives that support individual decision-making and promote innovation.
Europe and Germany can weather this crisis without a collapse in industrial production. We also have an opportunity to deal efficiently with the move to climate neutrality, aligned with Germany’s hydrogen strategy for imported low-carbon fuels. In both cases, we should have confidence in price signals as well as in the power of people and business to innovate and adapt.
National Grid power supply warning highlights electricity shortage risks amid low wind output, generator outages, and cold weather, reducing capacity margins and grid stability; considering demand response and reserve power to avoid blackout risk.
Key Points
An alert that reduced capacity from low wind and outages requires actions to maintain UK grid stability.
✅ Low wind output and generator outages reduce capacity margins
✅ ESO exploring demand response and reserve generation options
✅ Aim: maintain grid stability and avoid blackout risk
National Grid has warned that Britain’s electricity will be in short supply over the next few days after a string of unplanned power plant outages and unusually low wind speeds this week, as cheap wind power wanes across the system.
The electricity system operator said it will take action to “make sure there is enough generation” during the cold weather spell, including virtual power plants and other demand-side measures, to prevent a second major blackout in as many years.
“Unusually low wind output coinciding with a number of generator outages means the cushion of spare capacity we operate the system with has been reduced,” the company told its Twitter followers.
“We’re exploring measures and actions to make sure there is enough generation available to increase our buffer of capacity.”
A spokeswoman for National Grid said the latest electricity supply squeeze was not expected to be as severe as recorded last month, following reports that the government’s emergency energy plan was not going ahead, and added that the company did not expect to issue an official warning in the next 24 hours.
“We’re monitoring how the situation develops,” she said.
The warning is the second from the electricity system operator in recent weeks. In mid-September the company issued an official warning to the electricity market as peak power prices climbed, that its ‘buffer’ of power reserves had fallen below 500MW and it may need to call on more power plants to help prevent a blackout. The notice was later withdrawn.
Concerns over National Grid’s electricity supplies have been relatively rare in recent years. It was forced in November 2015 to ask businesses to cut their demand as a “last resort” measure to keep the lights on after a string of coal plant breakdowns.
But since then, National Grid’s greater challenge has been an oversupply of electricity, partly due to record wind generation, which has threatened to overwhelm the grid during times of low electricity demand.
National Grid has already spent almost £1bn on extra measures to prevent blackouts over the first half of the year by paying generators to produce less electricity during the coronavirus lockdown, as daily demand fell.
The company paid wind farms to turn off, and EDF Energy to halve the nuclear generation from its Sizewell B nuclear plant, to avoid overwhelming the grid when demand for electricity fell by almost a quarter from last year.
The electricity supply squeeze comes a little over a year after National Grid left large parts of England and Wales without electricity after the biggest blackout in a decade left a million homes in the dark. National Grid blamed a lightning strike for the widespread power failure.
Similar supply strains have recently caused power cuts in China, underscoring how weather and generation mix can trigger blackouts.
Oil and Gas Profitability Decline reflects shale-driven oversupply, OPEC-Russia dynamics, LNG exports, renewables growth, and weak demand, signaling compressed margins for producers, stressed petrodollar budgets, and shifting energy markets post-Covid.
Key Points
A sustained squeeze on hydrocarbon margins from agile shale supply, weaker OPEC leverage, and expanding renewables.
✅ Shale responsiveness caps prices and erodes industry rents
✅ OPEC-Russia cuts face limited impact versus US supply
✅ Renewables and EVs slow long-term oil and gas demand
The oil-price crash of March 2020 will probably not last long. As in 2014, when the oil price dropped below $50 from $110 in a few weeks, this one will trigger a temporary collapse of the US shale industry. Unless the coronavirus outbreak causes Armageddon, cheap oil will also support policymakers’ efforts to help the global economy.
But there will be at least one important and lasting difference this time round — and it has major market and geopolitical implications.
The oil price crash is a foretaste of where the whole energy sector was going anyway — and that is down.
It may not look that way at first. Saudi Arabia will soon realise, as it did in 2015, that its lethal decision to pump more oil is not only killing US shale but its public finances as well. Riyadh will soon knock on Moscow’s door again. Once American shale supplies collapse, Russia will resume co-operation with Saudi Arabia.
With the world economy recovering from the Covid-19 crisis by then, and with electricity demand during COVID-19 shifting, moderate supply cuts by both countries will accelerate oil market recovery. In time, US shale producers will return too.
Yet this inevitable bounceback should not distract from two fundamental factors that were already remaking oil and gas markets. First, the shale revolution has fundamentally eroded industry profitability. Second, the renewables’ revolution will continue to depress growth in demand.
The combined result has put the profitability of the entire global hydrocarbon industry under pressure. That means fewer petrodollars to support oil-producing countries’ national budgets, including Canada's oil sector exposures. It also means less profitable oil companies, which traditionally make up a large segment of stock markets, an important component of so many western pension funds.
Start with the first factor to see why this is so. Historically, the geological advantages that made oil from countries such as Saudi Arabia so cheap to produce were unique. Because oil and gas were produced at costs far below the market price, the excess profits, or “rent”, enjoyed by the industry were very large.
Furthermore, collusion among low-cost producers has been a winning strategy. The loss of market share through output cuts was more than compensated by immediately higher prices. It was the raison d’être of Opec.
The US shale revolution changed all this, exposing the limits of U.S. energy dominance narratives. A large oil-producing region emerged with a remarkable ability to respond quickly to price changes and shrink its costs over time. Cutting back cheap Opec oil now only increases US supplies, with little effect on world prices.
That is why Russia refused to cut production this month. Even if its cuts did boost world prices — doubtful given the coronavirus outbreak’s huge shock to demand — that would slow the shrinkage of US shale that Moscow wants.
Shale has affected the natural gas industry even more. Exports of US liquefied natural gas now put an effective ceiling on global prices, and debates over a clean electricity push have intensified when gas prices spike.
On top of all this, there is also the renewables’ revolution, though a green revolution has not been guaranteed in the near term. Around the world, wind and solar have become ever-cheaper options to generate electricity. Storage costs have also dropped and network management improved. Even in the US, renewables are displacing coal and gas. Electrification of vehicle fleets will damp demand further, as U.S. electricity, gas, and EVs face evolving pressures.
Eliminating fossil fuel consumption completely would require sustained and costly government intervention, and reliability challenges such as coal and nuclear disruptions add to the complexity. That is far from certain. Meanwhile, though, market forces are depressing the sector’s usual profitability.
The end of oil and gas is not immediately around the corner. Still, the end of hydrocarbons as a lucrative industry is a distinct possibility. We are seeing that in dramatic form in the current oil price crash. But this collapse is merely a message from the 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.”
Sidi Mansour Wind Farm Tunisia will deliver 30 MW as an IPP, backed by UPC Renewables and CFM, under a STEG PPA, supporting 2030 renewable energy targets, grid connection, job creation, and CO2 emissions reduction.
Key Points
A 30 MW wind IPP by UPC and CFM in Sidi Mansour, supplying STEG and advancing Tunisia's 2030 renewable target.
✅ 30 MW capacity under STEG PPA, first wind IPP in Tunisia
✅ Co-developed by UPC Renewables and Climate Fund Managers
✅ Cuts CO2 by up to 56,645 t and creates about 100 jobs
UPC Renewables (UPC) and the Climate Fund Managers (CFM) have partnered to develop a 30 megawatt wind farm in Sidi Mansour, Tunisia, which, amid regional wind expansion efforts, will help the country meet its 30% renewable energy target by 2030.
Tunisia announced the launch of its solar energy plan in 2016, with projects like the 10 MW Tunisian solar park aiming to increase the role of renewables in its electricity generation mix ten-fold to 30%,
This Sidi Mansour Project will help Tunisia meet its goals, reducing its reliance on imported fossil fuels and, mirroring 90 MW Spanish wind build milestones, demonstrating to the world that it is serious about further development of renewable energy investment.
“Chams Enfidha”, the first solar energy station in Tunisia with a capacity of 1 megawatt and located in the Enfidha region. (Ministry of Energy, Mines and Energy Transition Facebook page)
This project will also be among the country’s first Independent Power Producers (IPP). CFM is acting as sponsor, financial adviser and co-developer on the project, in a landscape shaped by IRENA-ADFD funding in developing countries, while UPC will lead the development with its local team. The team will be in charge of permitting, grid connection, land securitisation, assessment of wind resources, contract procurement and engineering.
UPC was selected under the “Authorisation Scheme” tender for the project in 2016, similar to utility-scale developments like a 450 MW U.S. wind farm, and promptly signed a power purchase agreement with Société Tunisienne Electricité et du Gaz (STEG).
Brian Caffyn, chairman of UPC Group, said: “We can start the construction of the Sidi Mansour wind farm in 2020, helping stimulate the Tunisian economy, create local jobs and a social plan for local communities while respecting international environmental protection guidelines.”
Sebastian Surie, CFM’s regional head of Africa, added: “CFM is thrilled to partner with a leading wind developer in the Sidi Mansour Wind Project to assist Tunisia in meeting its renewable energy goals. As potentially the first Wind IPP in Tunisia, this Project will be a testament to how CI1’s full life-cycle financing solution can unlock investment in renewable energy in new markets, as seen in an Irish offshore wind project globally.”
The project will not only provide electricity, but also reduce CO2 emissions by up to 56,645 tonnes and create some 100 new jobs.
Wind turbine in El Haouaria, Tunisia, highlighting advances such as a huge offshore wind turbine that can power 18,000 homes. (Reuters)
Tunisia’s first power station, “Chams Enfidha,” inaugurated at the beginning of July, has a capacity of one megawatt, with an estimated cost of 3.3 million dinars ($1.18 million). The state invested 2.3 million dinars into the project ($820,000), with the remaining 1 million dinars ($360,000) provided by a private investor.
Hydro-Qu e9bec COVID-19 M&A Pause signals a halt to international expansion as falling electricity demand, weaker exports, and revenue pressure shift capital to the Quebec economy, prioritizing domestic investment, strategic plan revisions, and risk management.
Key Points
Hydro-Qu e9bec COVID-19 M&A Pause halts overseas deals, shifting investment to Quebec as demand, exports and revenue fall.
✅ International M&A on hold; capital reallocated to Quebec projects
✅ Lower electricity demand reduces exports and spot prices
✅ Strategic plan and 2020 guidance revised downward
Quebec’s state-owned power generator and distributor has put international mergers and acquisitions on hold for the foreseeable future because of the COVID-19 crisis, chief financial officer Jean-Hugues Lafleur said Friday.
Former chief executive officer Éric Martel, who left last month, had made foreign expansion a key tenet of his growth strategy.
“We’re in revision mode” as pertains to acquisitions, Lafleur told reporters on a conference call, as the company pursues a long-term strategy to wean the province off fossil fuels at home as well. “I don’t see how Hydro-Québec could take $5 billion now and invest it in Chile because we have an investment opportunity there. Instead, the $5 billion will be invested here to support the Quebec economy. We’re going to make sure the Quebec economy recovers the right way before we go abroad.”
Lafleur spoke after Hydro-Québec reported a 14-per-cent drop in first-quarter profit and warned full-year results will fall short of expectations as COVID-19 weighs on power demand.
Net income in the three-month period ended March 31 was $1.53 billion, down from $1.77 billion a year ago, Hydro-Québec said in a statement. Revenue fell about six per cent to $4.37 billion.
“Due to the economic downturn resulting from the current crisis, we’re anticipating lower electricity sales in all of our markets,” Lafleur said. “Consequently, the financial outlook for 2020 set out in the strategic plan 2020–2024, which also reflects the province’s no-nuclear stance, will be revised downward.”
It’s still too early to determine the scope of the revision, the company said in its quarterly report. Hydro-Québec was targeting net income of between $2.8 billion and $3 billion in 2020, according to its strategic plan.
The first quarter was the utility’s last under Martel, who quit to take over at jetmaker Bombardier Inc. Quebec appointed former Énergir CEO Sophie Brochu to replace him, effective April 6.
First-quarter results “weren’t significantly affected” by the pandemic, Lafleur said on a conference call with reporters. Electricity sales generated $294 million less than a year ago due primarily to milder temperatures, he said.
Results will start to reflect COVID-19’s impact in the second quarter, though NB Power has signed three deals to bring more Quebec electricity into the province that could cushion some exports.
Electricity consumption in Quebec has fallen five per cent in the past two months, paced by an 11-per-cent plunge for commercial and institutional clients, and cities such as Ottawa saw a demand plunge during closures.
Industrial customers such as pulp and paper producers have also curbed power use, and it’s hard to see demand rebounding this year, Lafleur said.
“What we’ve lost since the start of the pandemic is not coming back,” he said.
Demand on export markets, meanwhile, has shrunk between six per cent and nine per cent since mid-March. The drop has been particularly steep in Ontario, reaching as much as 12 per cent, after the province chose not to renew its electricity deal with Quebec earlier this year, compared with declines of up to five per cent in New England and eight per cent in New York.
Spot prices in the U.S. have retreated in tandem, falling this week to as low as 1.5 U.S. cents per kilowatt-hour, Lafleur said. Hydro-Québec’s hedging strategy — which involves entering into fixed-price sales contracts about a year ahead of time — allowed the company to export power for an average of 4.9 U.S. cents per kilowatt-hour in the first quarter, compared with the 2.2 cents it would have otherwise made.
Investments will decline this year as construction activity proceeds at reduced speed, Lafleur said. Hydro-Québec was initially planning to invest about $4 billion in the province, he said, as it works to increase hydropower capacity to more than 37,000 MW across its fleet.
Physical distancing measures “are having an impact on productivity,” Lafleur said. “We can’t work the way we wanted, and project costs are going to be affected. Anytime we send workers north on a plane, we need to leave an empty seat beside them.”
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