Belleville nuclear in France undergoing generator maintenance

Advanced Nuclear Reactors redefine nuclear energy with SMRs, diverse fuels, passive safety, digital control rooms, and flexible heat and power, pairing veteran operator expertise with cost-efficient, carbon-free electricity for a resilient grid.

Key Points

SMR-based advanced reactors with passive cooling and digital controls deliver flexible power and process heat.

✅ Veteran operators transfer proven safety culture and risk management.

✅ SMRs, passive safety, and digital controls simplify operations.

✅ Flexible output: electricity, process heat, and grid support.

Advanced reactors will break the mold of what we think next-gen nuclear power can accomplish: some will be smaller, some will use different kinds of fuel and others will do more than just make electricity. This new technology may seem like uncharted waters, but when operators, technicians and other workers start up the first reactors of the new generation, they will bring with them years of nuclear experience to run machines that have been optimized with lessons from the current fleet.

While advanced reactors are often portrayed as the future of nuclear energy, and atomic energy is heating up across markets, its our current plants that have paved the way for these exciting innovations and which will be workhorses for years to come.

Reactor Veterans Bring Their Expertise to New Designs

Many of the workers who will operate the next generation of reactors come from a nuclear background. Even though the design of an advanced reactor may be different, the experience and instincts these operators have gained from working at the current fleet will help new plants get off to a more productive start.

They have a questioning attitude; they are always exploring what could go wrong and always understanding the notion of risk management in nuclear operations, whether its the oldest design or the newest design, said Chip Pardee, the president of Terrestrial Energy USA, who is the former chief operating officer at two nuclear utilities, Exelon Corp. and the Tennessee Valley Authority.

They have respect for the technology and a bias towards conservative decision-making.

Jhansi Kandasamy, vice president of engineering at GE Hitachi Nuclear Energy, agrees. She said that the presence of industry veterans will benefit the new modelslike the 300 megawatt boiling water reactor her company is developing.

From the beginning, a new reactor will have people who have touched it, worked on it, and experienced it, she said.

Theyre going to be able to tell you if something doesnt look right, because theyve lived through it.

Experience Informs New Reactor Design

Advanced reactors are designed by engineers who are fully familiar with existing plants and can use that experience to optimize the new ones, like a family building a house and wanting the kitchen just so. New reactors will be simpler to operate because of insights gained from years of operations of the current fleet, and some designs even integrate molten salt energy storage to enhance flexibility.

NuScale Power LLC, for example, has a very different design from the current fleet amid an advanced nuclear push that is reshaping development: up to 12 small reactorsinstead of one or two large reactorsmanaged from a single digital control roominstead of one full of analog switches and dials. When the company designed its control room, it brought in industry veterans who had collectively worked at more than two dozen nuclear plants.

The experts that NuScale brought in critiqued everything, even down to the shape of the symbols on the computer screens to make them easier to read for operators who sometimes need to quickly interpret lots of incoming data. The control panels for NuScales small modular reactor (SMR) present information according to its importance and automatically call up appropriate procedures for operators.

Many advanced reactors are also smaller than those currently operating, which makes their components simpler and less expensive. Kandasamy pointed out that the giant mechanical pumps in todays reactors generate a lot of heat and require a lot of supporting systems, including air conditioning in the rooms that house them.

GE Hitachis SMR design relies more on passive cooling so it needs fewer pumps, and those that remain use magnets, so they generate less heat. Fewer, smaller pumps means a smaller building and less cost.

Advanced Nuclear Will Further the Work of Current Reactors

Advanced reactors promise improved flexibility and the ability to do more kinds of work, including nuclear beyond electricity applications, to displace carbon and stabilize the climate. And they will continue nuclear energys legacy of providing reliable, carbon-free electricity, as a recent new U.S. reactor startup illustrates in practice. As new designs come on line over the next decade, we will continue to rely on operating plants which provide nearly 55 percent of the countrys carbon-free electricity.

The world will need all the carbon-free generation it can get for many years to come, as companies, states and countries aim for zero emissions by mid-century and pursue strategies like the green industrial revolution to accelerate deployment. That means it will need wind, solar, advanced reactors and current plants.

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DOE Grid Resilience Pricing Rule faces FERC review as energy groups challenge an expedited timeline to reward coal and nuclear for reliability in wholesale markets, impacting natural gas, renewables, baseload economics, and grid pricing.

Key Points

A DOE proposal directing FERC to compensate coal and nuclear plants for reliability attributes in wholesale markets.

✅ Industry coalition seeks normal FERC timeline and review

✅ Impacts wholesale pricing, baseload economics, reliability

✅ Request for 90-day comments and reply period

A coalition of 11 industry groups is pushing back on Energy Secretary Rick Perry's efforts to quickly implement a major change to the way electric power is priced in the United States.

The Energy Department on Friday proposed a rule that stands to bolster coal and nuclear power plants by forcing the regional markets that set electricity prices to compensate them for the reliability they provide. Perry asked the Federal Energy Regulatory Commission to consider and finalize the rule within 60 days, including a 45-day period during which stakeholders can issue comments.

On Monday, groups representing petroleum, natural gas, electric power and renewable energy interests including ACORE urged FERC to reject the expedited process, as well as the Department of Energy's request that the regulatory commission consider putting in place an interim rule.

They say the time frame is "aggressive" and the department didn't provide adequate justification for fast-tracking a process that could have huge impacts on wholesale electricity markets.

"This is one of the most significant proposed rules in decades related to the energy industry and, if finalized, would unquestionably have significant ramifications for wholesale markets under the Commission's jurisdiction," the groups said in the motion filed with FERC.

"The Energy Industry Associations urge the Commission to reject the proposed unreasonable timelines and instead proceed in a manner that would afford meaningful consideration of public comments and be consistent with the normal deliberative process that it typically affords such major undertakings," they said.

The groups are requesting a 90-day comment period, as well as another period for reply comments. FERC, which has authority to regulate interstate transmission and sale of electricity and natural gas, is not required to decide in favor of the rule but, amid a recent FERC decision that drew industry criticism, must consider it.

Expediting the process or imposing an interim rule is generally limited to emergencies, the groups said. The Energy Department's letter to FERC does not even attempt to establish that an immediate threat to U.S. electricity reliability exists, they allege.

• A coalition of energy industry groups asked regulators to reject a rule proposed by the U.S. Department of Energy on Friday.
• The rule would bolster coal-fired and nuclear power plants by requiring wholesale markets to compensate them for certain attributes.
• The groups say the Energy Department proposed "unreasonable timelines" for stakeholders to offer feedback on a rule with "significant ramifications for wholesale markets."

The groups cite a recent Energy Department report on grid reliability that concluded: "reliability is adequate today despite the retirement of 11 percent of the generating capacity available in 2002, as significant additions from natural gas, wind, and solar have come online since then."

The Department of Energy did not return a request for comment.

The Energy Department's rule marks a flashpoint in the battle between natural gas-fired and renewable energy and so-called baseload power sources like coal and nuclear.

Separately, coal and business groups have supported the EPA in litigation over the Affordable Clean Energy rule, as documented in legal challenges brought during the rule's defense.

Gas, wind and solar power have eaten into coal and nuclear's share of U.S. electric power generation in recent years. That is thanks to a boom in U.S. gas production that has pushed down prices, the rapid adoption of subsidized renewable energy and President Barack Obama's efforts to mitigate emissions from power plants, which the Trump administration has sought to replace with a tune-up as policies shift.

Electric power is priced in deregulated, wholesale markets in many parts of the country. Utilities typically draw on the cheapest power sources first.

Some worry that the retirement of coal-fired and nuclear power plants undermines the nation's ability to reliably and affordably deliver electricity to households and businesses.

President Donald Trump has vowed to revive the ailing coal industry, declaring an end to the 'war on coal' in public remarks. Trump, Perry and other administration officials reject the consensus among climate scientists that carbon emissions from sources like coal-fired plants are the primary cause of global warming.

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Los Angeles Power Station Fire prompts LADWP to shut a Northridge/Reseda substation, causing a San Fernando Valley outage amid a heatwave; high-voltage equipment and mineral oil burned as 94,000 customers lost power, elevator rescues reported.

Key Points

An LADWP substation fire in Northridge/Reseda caused a major outage; 94,000 customers affected as crews restore power.

✅ Fire started around 6:52 p.m.; fully extinguished by 9 p.m.

✅ High-voltage gear and mineral oil burned; no injuries reported.

✅ Outages hit Porter Ranch, Reseda, West Hills, Granada Hills.

About 94,000 customers were without electricity Saturday night after the Los Angeles Department of Water and Power shut down a power station in the northeast San Fernando Valley that caught fire, the agency said.

The fire at the station in the Northridge/Reseda area of Los Angeles started about 6:52 p.m. and involved equipment that carries high-voltage electricity and distributes it at lower voltages to customers in the surrounding area, the department said, even as other utilities sometimes deploy wildfire safety shut-offs to reduce risk during dangerous conditions.

The department shut off power to the station as a precautionary move, and it is restoring power now that the fire has been put out, similar to restoration after intentional shut-offs in other parts of California. Initially, 140,000 customers were without power. That number had been cut to 94,000 by 11 p.m.

The power outage comes as much of California baked in heat that broke records, and rolling blackout warnings were issued as the grid strained. A record that stood 131 years in Los Angeles was snapped when the temperature spiked at 98 degrees downtown.

People reported losing power in Porter Ranch, Winnetka, West Hills, Canoga Park, Woodland Hills, Granada Hills, North Hills, Reseda and Chatsworth, KABC TV reported, highlighting electricity inequality across communities.

Shortly after the blaze broke out, firefighters found a huge container of mineral oil that is used to cool electrical equipment on fire, Los Angeles Fire Department spokesman Brian Humphrey told the Los Angeles Times. The incident underscores infrastructure risks that in some regions have required a complete grid rebuild after severe storms.

Firefighters had the blaze under control by 8:30 p.m. and were able to put it out by 9 p.m., Humphrey said. "These were fierce flames, with smoke towering more than 300 feet into the sky," he told the newspaper.

No one was injured.

Firefighters rescued people who were stranded in elevators, Humphrey said.

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California Managed Decline of Fossil Fuels aligns oil phaseout with carbon neutrality, leveraging ZEV adoption, solar and wind growth, severance taxes, drilling setbacks, fracking oversight, CARB rules, and CalGEM regulation to deliver a just transition.

Key Points

California's strategy to phase out oil and gas while meeting carbon-neutral goals through policy, regulation, and equity.

✅ Severance taxes fund clean energy and workforce transition.

✅ Setbacks restrict drilling near schools, homes, and hospitals.

✅ CARB and CalGEM tighten fracking oversight and ZEV targets.

California’s energy past is on a collision course with its future. Think of major oil-producing U.S. states, and Texas, Alaska or North Dakota probably come to mind. Although its position relative to other states has been falling for 20 years, California remains the seventh-largest oil-producing state, with 162 million barrels of crude coming up in 2018, translating to tax revenue and jobs.

At the same time, California leads the nation in solar rooftops and electric vehicles on the road by a wide margin and ranking fifth in installed wind capacity. Clean energy is the state’s future, and the state is increasingly exporting its energy policies across the West, influencing regional markets. By law, California must have 100 percent carbon-free electricity by 2045, and an executive order signed by former Governor Jerry Brown calls for economywide carbon-neutrality by the same year.

So how can the state reconcile its divergent energy path? How should clean-energy-minded lawmakers wind down California’s oil and gas sector in a way that aligns with the state’s long-term climate targets while providing a just transition for the industry’s workforce?

Any efforts to reduce fossil fuel supply must run parallel to aggressive demand-reduction measures such as California’s push to have 5 million zero-emission vehicles on the road by 2030, said Ethan Elkind, director of Berkeley Law's climate program, especially amid debates over keeping the lights on without fossil fuels in the near term. After all, if oil demand in California remains strong, crude from outside the state will simply fill the void.

“If we don’t stop using it, then that supply is going to get here, even if it’s not produced in-state,” Elkind said in an interview.

Lawmakers have a number of options for policies that would draw down and eventually phase out fossil fuel production in California, according to a new report from the Center for Law, Energy and the Environment at the UC Berkeley School of Law, co-authored by Elkind and Ted Lamm.

They could impose a higher price on California's oil production through a "severance" tax or carbon-based fee, with the revenue directed to measures that wean the state from fossil fuels. (California, alone among major oil-producing states, does not have an oil severance tax.)

Lawmakers could establish a minimum drilling setback from schools, playgrounds, homes and other sensitive sites. They could push the state's oil and gas regulator, the California Geologic Energy Management Division, to prioritize environmental and climate concerns.

A major factor holding lawmakers back is, of course, politics, including debates over blackouts and climate policy that shape public perception. Given the state’s clean-energy ambitions, it might surprise non-Californians that the oil and gas industry is one of the Golden State’s most powerful special interest groups.

Overcoming a "third-rail issue" in California politics
The Western States Petroleum Association, the sector’s trade group in California's capital of Sacramento, spent $8.8 million lobbying state policymakers in 2019, more than any other interest group. Over the last five years, the group, which cultivates both Democratic and Republican lawmakers, has spent $43.3 million on lobbying, nearly double the total of the second-largest lobbying spender.

Despite former Governor Brown’s reputation as a climate champion, critics say he was unwilling to forcefully take on the oil and gas industry. However, things may take a different turn under Brown's successor, Governor Gavin Newsom.

In May 2019, when Newsom released California's midyear budget revision (PDF), the governor's office noted the need for "careful study and planning to decrease demand and supply of fossil fuels, while managing the decline in a way that is economically responsible and sustainable.”

Related reliability concerns surfaced as blackouts revealed lapses in power supply across the state.

Writing for the advocacy organization Oil Change International, David Turnbull observed, “This may mark the first time that a sitting governor in California has recognized the need to embark upon a managed decline of fossil fuel supply in the state.”

“It is significant because typically this is one of those third-rail issues, kind of a hot potato that governors don’t even want to touch at all — including Jerry Brown, to a large extent, who really focused much more on the demand side of fuel consumption in the state,” said Berkeley Law’s Elkind.

California's revised budget included $1.5 million for a Transition to a Carbon-Neutral Economy report, which is being prepared by University of California researchers for the California Environmental Protection Agency. In an email, a CalEPA spokesperson said the report is due by the end of this year.

Winding down oil and gas production
Since the release of the revised budget last May, Newsom has taken initial steps to increase oversight of the oil and gas industry. In July 2019, he fired the state’s top oil and gas regulator for issuing too many permits to hydraulically fracture, or frack, wells.

Later in the year, he appointed new leadership to oversee oil and gas regulation in the state, and he signed a package of bills that placed constraints on fossil fuel production. The next month, Newsom halted the approval of new fracking operations until pending permits could be reviewed by a panel of scientists at Lawrence Livermore National Laboratory. The California Geologic Energy Management Division (CalGEM) did not resume issuing fracking permit approvals until April of this year.

Not all steps have been in the same direction. This month Newsom dropped a proposal to add dozens of analysts, engineers and geologists at CalGEM, citing COVID-related economic pressure. The move would have increased regulatory oversight on fossil fuel producers and was opposed by the state's oil industry.

Ultimately, more durable measures to wind down fossil fuel supply and demand will require new legislation, even as regulators weigh whether the state needs more power plants to maintain reliability.

A 2019 bill by Assemblymember Al Muratsuchi (D-Torrance), AB 345, would have codified the minimum 2,500-foot setback for new oil and gas wells. However, before the final vote in the Assembly, the bill’s buffer requirement was dropped and replaced with a requirement for CalGEM “to consider a setback distance of 2,500 feet.” The bill passed the Assembly in January over "no" votes from several moderate Democrats; it now awaits action in the Senate.

A bill previously introduced by Assemblymember Phil Ting (D-San Francisco), AB 1745, didn’t even make it that far. Ting’s bill would have required that all new passenger cars registered in the state after January 1, 2040, be zero-emission vehicles (ZEV). The bill died in committee without a vote in April 2018.

But the backing of the California Air Resources Board (CARB), one of the world's most powerful air-quality regulators, could change the political conversation. In March, CARB chair Mary Nichols said she now supports consideration of California establishing a 100 percent zero-emission vehicle sales target by 2030, as policymakers also consider a revamp of electricity rates to clean the grid.

“In the past, I’ve been skeptical about whether that would do more harm than good in terms of the backlash by dealers and others against something that sounded so un-California like,” Nichols said during an online event. “But as time has gone on, I’ve become more convinced that we need to send the longer-term signal about where we’re headed.”

Another complicating factor for California’s political leaders is the lack of a willing federal partner — at least in the short term — in winding down oil and gas production, amid warnings about a looming electricity shortage that could pressure the grid.

Under the Trump administration, the Bureau of Land Management, which oversees 15 million acres of federal land in California, has pushed to open more than 1 million acres of public and private land across eight counties in Central California to fracking. In January 2020, California filed a federal lawsuit to block the move.

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Canada Oil Recession Outlook analyzes the Russia-Saudi price war, OPEC discord, COVID-19 demand shock, WTI and WCS collapse, Alberta oilsands exposure, U.S. shale stress, and GDP risks from blockades and fiscal responses.

Key Points

An outlook on how the oil price war and COVID-19 demand shock could tip Canada into recession and strain producers.

✅ WTI and WCS prices plunge on OPEC-Russia discord

✅ Alberta oilsands face break-even pressure near 30 USD WTI

✅ RBC flags global recession; GDP hit from blockades, virus

A war between Russia and Saudi Arabia for market share for oil may have been triggered by the COVID-19 pandemic in China, but the oil price crash contagion that it will spread could have impacts that last longer than the virus.

The prospects for Canada are not good.

Plunging oil prices, reduced economic activity from virus containment, and the fallout from weeks of railway blockades over the Coastal GasLink pipeline all add up to “a one-two-three punch that I think is almost inevitably going to put Canada in a position where its growth has to be negative,” said Dan McTeague, a former Liberal MP and current president of Canadians for Affordable Energy. The situation “certainly has the makings” of a recession, said Ken Peacock, chief economist for the Business Council of British Columbia.

“At a minimum, it’s going to be very disruptive and we’re going to have maybe one negative quarter,” Peacock said. “Whether there’s a second one, where it gets labeled a recession, is a different question. But it’s going to generate some turmoil and challenges over the next two quarters – there’s no doubt about that.”

RBC Economics on March 13 announced it now predicts a global recession and cut its growth projections for Canada's economy in 2020 by half a per cent.

Oil price futures plunged 30% last week, dragging stock markets and currencies, including the Canadian dollar, down with them, even as a deep freeze strained U.S. energy systems. That drop came on top of a 17% decline in February, due to falling demand for oil due to the virus.

The latest price plunge – the worst since the 1991 Gulf War – was the result of Russia and the Organization of Petroleum Exporting Countries (OPEC), led by Saudi Arabia, failing to agree on oil production cuts.

The COVID-19 outbreak in China – the world’s second-largest oil consumer – had resulted in a dramatic drop in oil demand in that country, and a sudden glut of oil, with the U.S. energy crisis affecting electricity, gas and EV markets.

OPEC has historically been able to moderate global oil prices by controlling output. But when Russia refused to co-operate with OPEC and agree to production cuts, Saudi Arabia’s state-owned company, Aramco, announced it plans to boost its oil output from 9.7 million barrels per day (bpd) to 12.3 million bpd in April.

In response to that announcement, West Texas Intermediate (WTI) prices dropped 18% to below US$34 per barrel while the Canadian Crude Index fell 24% to US$21. Western Canadian Select dropped 39% to US$15.73.

The effect on Alberta oilsands producers was severe and immediate. Cenovus Energy Inc. (TSX:CVE) saw roughly $2 billion in market cap erased on March 9, when its stock dropped by 52%, which came on top of a 12% drop March 6.

The company responded the very next day by announcing it would cut spending by 32% in 2020, suspend its oil-by-rail program and defer expansion projects.

MEG Energy Corp. (TSX:MEG), which suffered a 56% share price drop on March 9, also announced a 20% reduction in its 2020 capital spending plan.

Peter Tertzakian, chief economist for ARC Energy Research Institute, wrote last week that Russia’s plan is to try to hurt U.S. shale oil producers, who have more than doubled U.S. oil production over the past decade.

Anas Alhajji, a global oil analyst, expects that plan could work. Even before the oil price shock, he had predicted the great shale boom in the U.S. was coming to an end.

“Shale production will decline, and the myth of ‘explosive growth’ will end,” he told Business in Vancouver. “The impact is global and Canadian producers might suffer even more if the oil that Saudi Arabia sends to the U.S. is medium and heavy. This might last longer than what people think.”

The question for Alberta is how Canadian producers can continue to operate through a period of cheap oil. Alberta producers do not compete on the global market. They serve a niche market of U.S. heavy oil refiners, and Biden-era policy is seen as potentially more favourable for Canada’s energy sector than alternatives.

“On the positive side, the industry is battle-hardened,” Tertzakian wrote. “Over the past five years, innovative companies have already learned to endure some of the lowest prices in the world.”

But he added that they need WTI prices of US$30 per barrel just to break even.

“But that’s an average break-even threshold for an industry with a wide variation in costs. That means at that level about half the companies can’t pay their bills and half are treading water.”

Just prior to the oil price plunge, the International Energy Agency (IEA) updated its 2020 forecast for global oil consumption from an 825,000 bpd increase in oil consumption to a 90,000 bpd decrease, due to the COVID-19 virus and consequent economic contraction and reduction in travel.

The IEA predicts global oil demand won’t return to “normal” until the second half of 2020. But even if demand does return to pre-virus levels, that doesn’t mean oil prices will – not if Saudi Arabia can sustain increased oil production at low prices, and evolving clean grid priorities could influence the trajectory too.

The oil plunge was greeted in Alberta with alarm. Alberta Premier Jason Kenney warned Alberta is in “uncharted territory” as consumers are urged to lock in rates and said his government might have to review its balanced budget and resort to emergency deficit spending.

While British Columbians – who pay some of the highest gasoline prices in North America – will enjoy lower gasoline prices at a time when prices are usually starting a seasonal spike, B.C.’s economy could feel knock-on effects from a recession in Alberta.

“We sell a lot of inputs, do a lot of trade with Alberta, so it’s important for B.C., Alberta’s economic health,” Peacock said, “and recent tensions over electricity purchase talks underscore that.”

Last week, the Trudeau government announced $1 billion in emergency funding to cope with the virus and waived a one-week waiting period for unemployment insurance.

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Canada Clean Electricity drives a net-zero grid by 2035, scaling renewables like wind, solar, and hydro, with storage, smart grids, interprovincial transmission, and electrification of vehicles, buildings, and industry to cut emissions and costs.

Key Points

Canada Clean Electricity is a shift to a net-zero grid by 2035 using renewables, storage, and smart grids to decarbonize

✅ Doubles non-emitting generation for electrified transport and heating

✅ Expands wind, solar, hydro with storage and smart-grid balancing

✅ Builds interprovincial lines and faster permitting with Indigenous partners

By Merran Smith and Mark Zacharias

Canada is an electricity heavyweight. In addition to being the world’s sixth-largest electricity producer and third-largest electricity exporter in the global electricity market today, Canada can boast an electricity grid that is now 83 per cent emission-free, not to mention residential electricity rates that are the cheapest in the Group of Seven countries.

Indeed, on the face of it, the country’s clean electricity system appears poised for success. With an abundance of sunshine and blustery plains, Alberta and Saskatchewan, the Prairie provinces most often cited for wind and solar, have wind- and solar-power potential that rivals the best on the continent. Meanwhile, British Columbia, Manitoba, Quebec, and Newfoundland and Labrador have long excelled at generating low-cost hydro power.

So it would only be natural to assume that Canada, with this solid head start and its generous geography, is already positioned to provide enough affordable clean electricity to power our much-touted net-zero and economic ambitions.

But the reality is that Canada, like most countries, is not yet prepared for a world increasingly committed to carbon neutrality, in part because demand for solar electricity has lagged, even as overall momentum grows.

The federal government’s forthcoming Clean Electricity Standard – a policy promised by the governing Liberals during the most recent election campaign and restated for an international audience by Prime Minister Justin Trudeau at the United Nations’ COP26 climate summit – would require all electricity in the country to be net zero by 2035 nationwide, setting a new benchmark. But while that’s an encouraging start, it is by no means the end goal. Electrification – that is, hooking up our vehicles, heating systems and industry to a clean electricity grid – will require Canada to produce roughly twice as much non-emitting electricity as it does today in just under three decades.

This massive ramp-up in clean electricity will require significant investment from governments and utilities, along with their co-operation on measures and projects such as interprovincial power lines to build an electric, connected and clean system that can deliver benefits nationwide. It will require energy storage solutions, smart grids to balance supply and demand, and energy-efficient buildings and appliances to cut energy waste.

While Canada has mostly relied on large-scale hydroelectric and nuclear power in the past, newer sources of electricity such as solar, wind, geothermal, and biomass with carbon capture and storage will, in many cases, be the superior option going forward, thanks to the rapidly falling costs of such technology and shorter construction times. And yet Canada added less solar and wind generation in the past five years than all but three G20 countries – Indonesia, Russia and Saudi Arabia, with some experts calling it a solar power laggard in recent years. That will need to change, quickly.

In addition, Canada’s Constitution places electricity policy under provincial jurisdiction, which has produced a patchwork of electricity systems across the country that use different energy sources, regulatory models, and approaches to trade and collaboration. While this model has worked to date, given our low consumer rates and high power reliability, collaborative action and a cohesive vision will be needed – not just for a 100-per-cent clean grid by 2035, but for a net-zero-enabling one by 2050.

Right now, it takes too long to move a clean power project from the proposal stage to operation – and far too long if we hope to attain a clean grid by 2035 and a net-zero-enabling one by 2050. This means that federal, provincial, territorial and Indigenous governments must work with rural communities and industry stakeholders to accelerate the approvals, financing and construction of clean energy projects and provide investor certainty.

In doing so, Canada can set a course to carbon neutrality while driving job creation and economic competitiveness, a transition many analyses deem practical and profitable in the long run. Our closest trading partners and many of the world’s largest companies and investors are demanding cleaner goods. A clean grid underpins clean production, just as it underpins our climate goals.

The International Energy Agency estimates that, for the world to reach net zero by 2050, clean electricity generation worldwide must increase by more than 2.5 times between today and 2050. Countries are already plotting their energy pathways, and there is much to learn from each other.

Consider South Australia. The state currently gets 62 per cent of its electricity from wind and solar and, combined with grid-scale battery storage, has not lost a single hour of electricity in the past five years. South Australia expects 100 per cent of its electricity to come from renewable sources before 2030. An added bonus given today’s high energy prices: Annual household electricity costs have declined there by 303 Australian dollars ($276) since 2018.

The transition to clean energy is not about sacrificing our way of life – it’s about improving it. But we’ll need the power to make it happen. That work needs to start now.

Merran Smith is the executive director of Clean Energy Canada, a program at the Morris J. Wosk Centre for Dialogue at Simon Fraser University in Vancouver. Mark Zacharias is a special adviser at Clean Energy Canada and visiting professor at the Simon Fraser University School of Public Policy.

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