This story is part of a series called Shockwave: Rising energy demand and the future of the Great Lakes. The Great Lakes region is in the midst of a seismic energy shakeup, from skyrocketing data centre demand and a nuclear energy boom, to expanding renewables and electrification. In 2026, the Great Lakes News Collaborative will explore how shifting supply and demand affect the region and its waters.

Summary

• Wind blowing across the Great Lakes could generate clean electricity for the energy-hungry cities in the region, but there are currently no offshore wind projects harnessing that potential.
• Barriers to offshore wind on the Great Lakes include ecological concerns, regulatory hurdles and economic costs.
• Advocates say easing political restrictions and providing subsidies could kick-start an offshore wind industry in the region, and that ecological risks can be mitigated.

Covering an area the size of the United Kingdom and surrounded by half a dozen large, energy-hungry metropolitan regions, the Great Lakes region, surprisingly, boasts not a single offshore wind energy project.

We know that the resource and the demand are there. But no offshore wind effort has ever taken off.

Past efforts at a demonstration project called Icebreaker Wind, slated for Lake Erie off the coast of Cleveland, Ohio, fizzled out in 2023. In Ontario, which boasts 8,000 kilometres of Great Lakes coastline, a moratorium on offshore wind has been in place since 2011, with the provincial government having to fork over millions of dollars in damages to one wind energy company as a result.

But today, with electricity prices surging around the region, is it finally time for offshore wind to take its place? Do communities even want them?

Here, we speak to advocates for and opponents to offshore wind and investigate the myriad challenges such projects in the Great Lakes face.

What’s changing now?

A perfect storm of events has combined to push electricity prices to record levels for thousands of communities around the region.

Utility companies such as Consumers Energy in Michigan, We Energies, which operates in Wisconsin and Michigan’s Upper Peninsula and a host of others have embarked on system upgrades that are set to add up to 14 per cent to the cost of monthly electricity bills for consumers, with further rate hikes likely in the years ahead.

On top of that, the U.S. government has mandated that coal-fired electricity plants in Michigan, Indiana, Pennsylvania and elsewhere that were scheduled to be retired now remain open. That means that federal subsidies that are essential for keeping these loss-making plants running are likely to cost ratepayers billions more dollars.

Then there’s the contentious wave of data centres opening across the region, creating a huge new demand for utility-scale electricity.

All the while, recent years have seen a drive to reach net-zero carbon emissions. Michigan, Wisconsin and Minnesota plan to reach that goal by 2050.

Ontario aims to get to 80 per cent below its 1990 level of carbon emissions in the same time. New York state has declared an even more ambitious plan, to reach net zero by 2040.

On top of that, with the U.S. government banning offshore wind projects in oceans surrounding the country, there’s been a renewed push to see the Great Lakes — controlled by eight U.S. states and Ontario, rather than authorities in Washington, D.C., and Ottawa — become a new front in the development of the technology.

What is the energy potential for offshore wind on the Great Lakes?

Experts say offshore wind generated from the lakes could provide three times the amount of the electricity used by the eight U.S. Great Lakes states in 2023. National Oceanic and Atmospheric Administration data from 2021 crunched by the Woodwell Climate Research Center found that Great Lakes water generates more wind than anywhere else east of the Mississippi River.

“According to reports done for Ontario’s Ministry of Natural Resources, Great Lakes offshore wind can be implemented with minimal aquatic impacts. If the turbines are 10 to 15 kilometres offshore, they will be almost invisible,” said Jack Gibbons of the Ontario Clean Air Alliance.

“Offshore wind in the Canadian section of the Great Lakes has the potential to supply more than 100 per cent of Ontario’s electricity needs.”

Icebreaker Wind, the Cleveland project, got as far as securing a 50-year lake-bed lease from the State of Ohio in 2014. Predicted to provide 20 megawatts of electricity, enough to power more than 7,000 homes, its main goal was to function as a trial project.

But Icebreaker Wind is not completely dead, yet. Last year, a Maryland-based company called Mighty Waves Energy acquired the project, raising hopes among Cleveland leaders and many residents around the region that the first steps towards a lake-based wind energy future remain in place.

Mark Hessels, CEO of Mighty Waves Energy, spoke with Great Lakes Now over the phone, but declined to go on the record to discuss the company’s proposed new offshore wind project, and failed to provide a statement when asked.

What are the big challenges?

And yet, the barriers appear immense.

John Lipaj has been sailing and boating on Lake Erie ever since he was a child.

“I spent every summer out there on a boat. In July and August, when the temperatures rise, the wind would die,” he said, illustrating one of several reasons he and others think offshore wind isn’t suitable for Lake Erie.

“If there’s no wind at exactly the time of year when electricity is needed most, for air conditioning, then what’s the point of building offshore wind?”

As a board member of the Lake Erie Foundation, a non-profit, that’s not the main reason he and the organization he represents opposes offshore wind on Lake Erie.

“One of the things we were most concerned about is that bald eagles were almost extinct, and they’ve really come back along the Lake Erie shore. Now, they’re thriving,” he said.

“In the winter, they’ll fly out a couple of miles [offshore] looking for fish, especially if there’s ice [on the shoreline]. We’ve got real concerns about the bald eagle population being hurt by the wind turbine out on the lake, because that’s their feeding ground.”

In 2022, a wind energy company was fined US$8 million and sentenced to probation after its wind turbines were found to have killed more than 150 eagles over the course of a decade across ten U.S. states, including Michigan and Illinois.

Some conservation organizations opposing offshore wind have even come under fire. A report by Grist in 2021 alleged that the American Bird Conservancy, a US$30-million non-profit, has been one of the most powerful environment-focused opponents to wind turbine projects across the country, having received around US$1 million from fossil fuel interests.

A request by Great Lakes Now for comment from the American Bird Conservancy was not received by the time of publication.

All the while, others believe the potential threat to wildlife can be mitigated.

“Some people are unaware that the National Audubon Society supports Great Lakes offshore wind power. The good news is that offshore wind can be done in a bird-friendly way,” said Gibbons of the Ontario Clean Air Alliance.

“We are recommending that the turbines should be turned off from dusk to dawn during the migratory bat seasons (late April and May and mid-July to the end of September) when wind speeds are less than seven metres per second, since bats fly more when wind speeds are low.”

Threats to wildlife aside, for Melissa Scanlan, director of the University of Wisconsin-Milwaukee’s Center for Water Policy, five leading factors have combined to stall progress in offshore wind:

• Jurisdictional fragmentation that prevents states and provinces from combining their efforts; 
• Inadequate planning;
• Policy instability at the federal government level; 
• Protracted litigation in the case of Ohio; and,
• A lack of sustained political will. 

There are other challenges.

“There’s definitely misinformation that circulates about offshore wind,” she said.

“From the research we’ve done, we think you can address that through transparent, science-based planning processes,” said Scanlan. “Without doing a more rigorous science-based planning process, if there’s a vacuum of reliable information, that can allow misinformation to be circulated more freely.”

On top of that, there are reservations around the economic return of such projects. Estimates suggest the cost of offshore wind on the Great Lakes could range from 7.5 to 12.9 cents per kilowatt hour. That’s more than double the cost of onshore wind or utility-scale solar.

But while the costs of delivering offshore wind are not inconsiderable, experts such as Scanlan say there’s also both a dollar and environmental cost of continuing to deploy fossil fuels for electricity generation.

Moreover, interest groups have allegedly been at work to make such efforts difficult to bring to fruition.

The former proprietor of the Icebreaker Wind project, the Lake Erie Energy Development Corp., has claimed that corruption within Ohio’s energy regulatory body and state leaders’ close ties to energy giant FirstEnergy made the project unworkable, and has sued FirstEnergy for up to US$10 million. Restrictions that the project faced, including calling for turbines to be shut down at night for eight months of the year, essentially torpedoed the project.

What would facilitate off-shore wind?

Industry innovators say that an easing of regulations at the state level would make a huge difference to the emergence of offshore wind in the Great Lakes. Investment in the form of tax breaks from state governments, which handle the leases and permits for any offshore wind projects in the Great Lakes, are another way. 

And while the cost of producing offshore wind is higher than its onshore equivalent, higher winds offshore combined with technological advances mean that energy production capacity from offshore could be up to 60 per cent more than onshore.

Scanlan of the University of Wisconsin-Milwaukee’s Center for Water Policy is among the researchers who say offshore wind projects could play a significant role in meeting our rapidly growing energy needs.

“As a society, we need to develop energy resources that are not in conflict with protecting the environment,” she said.

“Offshore wind is no different from that.”

The Narwhal’s reporters are telling environment stories you won’t read about anywhere else. Stay in the loop by signing up for our free weekly dose of independent journalism.

Summary

• B.C.’s throne speech was not delivered in 2026 due to the tragic shooting in Tumbler Ridge.
• The Narwhal obtained a copy of the speech via freedom of information request.
• The unshared speech gives an insight into B.C.’s priorities which include mining and liquefied natural gas (LNG).

In a typical year, the spring sitting of the B.C. legislature starts with a throne speech.

The speech from the throne — as the document is formally known — is delivered by the lieutenant-governor on behalf of the provincial government. It is a snapshot of the political moment, a mixture of policies and milestones the government of the day considers accomplishments, as well as hints about legislative priorities for the coming months.

For journalists who cover the legislature, the throne speech is an opportunity to peer at the political tea leaves and guess at what lies ahead.

But in 2026, the government’s planned throne speech was never presented in the legislature. Two days before its scheduled delivery, a horrific event occurred in the small town of Tumbler Ridge, B.C.: a mass shooting that resulted in the deaths of nine people, many of them students and staff at Tumbler Ridge Secondary School.

In the wake of the tragedy, the date set for the throne speech was postponed and the province observed a day of mourning. A few days later, Lieutenant-Governor Wendy Cocchia delivered a short and somber speech dedicated to the community of Tumbler Ridge.

But what was in the speech the government was poised to deliver? The Narwhal filed a freedom of information request for a copy of the speech with Premier David Eby’s office. And we received a mostly un-redacted copy.

Over the year ahead, the B.C. government plans to continue championing liquefied natural gas (LNG) and mining development, which — along with forestry — form the province’s economic foundation, according to the speech.

“This natural inheritance remains central to our future prosperity,” the speech says.British Columbians should look forward to “a more sustainable forestry sector,” even as tariffs imposed by the United States continue to bite, the speech says. The government will also continue to work toward “delivering B.C. energy to growing markets” — supporting companies producing LNG to ship to markets on the other side of the Pacific — and “driving momentum on critical minerals,” it says.

A section of the speech is dedicated to the North Coast transmission line, which the government says will deliver “clean, reliable electricity needed to unlock tens of billions of dollars worth of private sector projects across” northwest B.C. The transmission line may almost exclusively serve large industrial customers, such as the Ksi Lisims LNG facility and multiple proposed mines. But its cost, which was most recently estimated at $6 billion for a little more than half the line’s length, will be shared between all BC Hydro ratepayers. 

The North Coast transmission line will be built “in true partnership with First Nations,” the throne speech says before it segues into a section titled “Reconciliation and Partnerships with Indigenous Peoples.”

‘Reconciliation is the responsibility of elected governments,’ throne speech says

For its next 431 words, the throne speech highlights the importance of reconciliation with First Nations and the work the province has done since the unanimous passage of the Declaration on the Rights of Indigenous Peoples Act in November 2019. It affirms the existence of Aboriginal Title, recognized by Canadian courts and in the Canadian Constitution.

“Reconciliation is the responsibility of elected governments,” according to the throne speech. 

“Repealing the Declaration Act, or walking away from negotiations with First Nations, would not change that reality,” the throne speech says. “It would create chaos, delays, lost jobs, and endless lawsuits.”

On page 13, the tone of the speech shifts as it mentions “recent court decisions [that] have raised questions about what reconciliation means in practice.” While those decisions aren’t named in the speech, the province is seeking to appeal a December 2025 decision by the B.C. Court of Appeal, which agreed with an argument from the Gitxaała and Ehattesaht First Nations that the government’s obligations under the Declaration Act — to align provincial laws with the principles of the United Nations Declaration on the Rights of Indigenous Peoples — are legally enforceable.

Since December, Eby has been touting plans to amend the Declaration Act to “address some serious legal liabilities that were created … through the court decision.” This angered First Nations leaders across B.C., who told Eby in a meeting last week that his plans to amend the law were “totally unacceptable.” So, on April 2, he made an abrupt announcement saying he would suspend parts of the Declaration Act and the Interpretation Act in the coming weeks instead.

However, suspension still requires legislative amendments, which will be voted on in the legislature by May 28. 

Eby said he is willing to risk the future of his government to get it done.

“This will be a confidence vote,” Eby told reporters on April 2. That means if the majority of MLAs vote against the legislation, the NDP government will have lost the confidence of the house, likely triggering a snap election.

These plans to change the landmark Indigenous Rights law over the objections of many First Nations leaders seem contradictory to the throne speech promise that the B.C. government “will not abandon responsibility for reconciliation.”

You can read the entire 25 pages of the throne speech here, except for a few lines redacted by the premier’s office under section 12 of the Freedom of Information and Protection of Privacy Act, which covers matters discussed in cabinet. 

The Narwhal’s reporters are telling environment stories you won’t read about anywhere else. Stay in the loop by signing up for our free weekly dose of independent journalism.

This story is part of a series called Shockwave: Rising energy demand and the future of the Great Lakes. The Great Lakes region is in the midst of a seismic energy shakeup, from skyrocketing data centre demand and a nuclear energy boom, to expanding renewables and electrification. In 2026, the Great Lakes News Collaborative will explore how shifting supply and demand affect the region and its waters.

Summary

• Reusing waste heat could help the Great Lakes reduce climate change emissions from heating and cooling buildings.
• The region has a huge opportunity for energy innovation that could reduce costs to consumers and limit damage to land and water.
• The biggest barriers are political and organizational.

We’re trying out staff-written summaries. Did you find this useful? YesNo

The energy system in the Great Lakes region, as in most parts of North America, is wasteful. Stupendously wasteful.

Consider these data points. Two-thirds of the energy generated by the 2,100-megawatt Pickering Nuclear Generating Station, east of Toronto, comes in the form of heat, not electricity. The excess heat is transferred to cooling water that is dumped into Lake Ontario.

For data centres, a booming, voracious energy user, nearly all the electricity that enters a facility to power servers turns into heat. Ejecting that heat so that the servers continue to support Zoom calls and ChatGPT queries can consume gobs of energy and water.

Even underground business and household waste holds wasted energy. Sewage flows in pipes at an average temperature of roughly 15 C, a thermal energy source waiting for an enterprising soul to tap into and extract the heat.

A movement is underway to do just that — mine the region’s power plants, data centres and sewers for heat and use it to develop cleaner, cheaper energy that helps reduce or remove carbon emissions from heating and cooling. The same practices cut the expense of adding new electric generating capacity.

Such a transformation is certainly possible and has been embraced in northern Europe. But it will not be easy here. Though the physics and equipment for waste-heat recovery are tested and proven, other barriers — financial, organizational and political — are more formidable hurdles for a region and a country in which energy efficiency is less valued than energy expansion.

“It’s not a technology issue,” said Luke Gaalswyk, president and chief executive officer of Ever-Green Energy, a district energy company based in St. Paul, Minnesota, that is eyeing wastewater as a heat source. “The engineering of this is well understood. It’s an awareness issue, it’s a funding issue, it’s a priority issue. We, the United States, don’t have the same policy frameworks or funding mechanisms that Europeans do as it relates to these sorts of projects and incentivizing waste-heat recovery.”

Gaalswyk and others see tantalizing opportunities for waste heat in aiding the region’s electric transition. The benefits include cheaper energy, less exposure to fossil fuel price fluctuations, fewer carbon emissions, less land disruption to build new generating and transmission capacity, and less thermal pollution into waterways. But getting there, they say, requires foundational shifts in understanding, attitudes and public policy. 

A new energy scenario

Electricity demand in the Great Lakes is growing, in some states for the first time in decades. If the projected buildout occurs, data centres will gobble electricity while the climate-friendly push to electrify everything boosts demand for electrons. 

Thermal networks, such as district heating systems that circulate hot water or steam to multiple buildings, garner less attention. Comparable to a home radiator at scale, they have been part of the urban energy landscape for more than a century, predating the invention of the gas-powered automobile. College campuses have them, as do hospital complexes. Cities like St. Paul, Chicago, Rochester and Lansing use district heating or cooling in their downtown cores. Toronto has a district cooling system that uses water drawn from deep in Lake Ontario to cool 80 buildings.

Waste heat — or, heat that is currently regarded as waste — could be a new reservoir of energy for district heating systems.

To find one source, building owners need only look beneath their basements. Promoting sewer thermal energy is a passion project for Paul Kohl, the board chair of the Sewer Thermal Energy Network, a trade association founded in 2023 to advocate for an unsung energy source. “We thought, let’s get people talking about it,” he said.

Kohl’s primary pitch is that sewer thermal energy goes hand-in-hand with reducing greenhouse gas emissions from buildings. Say an office complex wants to stop burning fuel oil for heat and instead wants to install a heat pump. An air-source heat pump, which extracts heat from ambient air, is a common option. But it can be problematic in an era of constrained electricity supply.

“What we’re finding is there are certain entities that are really excited about electrifying their building stock but they’re running into electrical demand problems,” Kohl said. “They can’t get enough electricity from the supplier.”

Enter sewer thermal. The building owner could instead tap into the sewer line running beneath the property and circulate the wastewater through a water-based heat pump that extracts the heat. The sewage is always contained and is not a health risk for those in the building. The water-based heat pump still uses electricity, but because of water’s superior capacity to transfer heat, its electricity demand is about half that of an air-based unit. In short, the well-understood thermal dynamics of water translate into substantial energy savings.

The sewer is a heat resource that constantly renews itself — people take showers, do laundry and wash dishes every day, using hot water in the process. The heat that went into the water could be used again. So why aren’t there more such systems? Kohl cited two major obstacles. One is knee-jerk revulsion, typically from the general public. “The ‘ick’ factor,” he said. 

The second is an unwillingness from utilities to allow other organizations to access their pipe infrastructure when it is not the utility’s mandate to do so. The utilities, he said, are more concerned with regulatory compliance and ensuring the integrity of their pipes.

Asked if his organization operates like a matchmaker, uniting parties that otherwise might not have met, Kohl turned the analogy around. A matchmaker works only if there are willing participants, he said. “A lot of water and wastewater utilities are the consummate bachelors. So they’re like, ‘If I never have to do this, great.’”

What brings utilities into the market? Progressive leadership, Kohl said.

Leaders heating the way

That leadership is on display in pockets around the Great Lakes region, from both the public and private sectors. 

In St. Paul, Ever-Green Energy has drawn up plans to tap the heat in the roughly 650,000,000 litres of wastewater that flows daily out of the Metropolitan Council’s treatment plant and into the Mississippi River. The US $150 million project would use the wastewater heat to replace the natural gas that currently fuels half of the district energy system, which is the largest hot water system in the United States.

Project proponents, including the City of St. Paul and Ever-Green, applied for the U.S. Environmental Protection Agency’s climate pollution reduction grant in 2024 but they were not selected. (Ever-Green’s wastewater heat project in Duluth also was not selected for the grant.) Though Clean Heat St. Paul, as the project is known, is currently unfunded, leaders continue to advocate for it.

“It presents an enormous opportunity for our community, for our state, to build a project that would generate global recognition around what’s possible with linking up wastewater and district heating,” Gaalswyk said.

Across the border, Toronto Western Hospital, part of the city’s leading hospital system, partnered with Noventa, an energy company, to install the world’s largest raw sewage thermal system. Completed in 2025, the project provides about 90 per cent of the hospital’s heating and cooling. 

Also in Toronto, Enwave, a district energy company, operates the Deep Lake Water Cooling system that uses cold water drawn from Lake Ontario to cool 115 buildings before the water is sent to taps as drinking water. Enwave, which operates systems across eastern Canada, is now adapting that system to utilize waste heat from the cooling operations so that heating and cooling work in tandem. At the same time, the company is considering sewer heat recovery from a wastewater treatment plant in Mississauga, Ont.

“The idea is you’re trying to capture waste heat in whatever form you can find it in,” said Carson Gemmill, vice president for solutions and innovations at Enwave.

More trade associations are embracing that logic. The Boltzmann Institute, a group of engineers focused on obstacles to electrification, persuaded the Ontario Society of Professional Engineers to start a campaign in September 2025 to advocate for thermal energy systems. Since the province is considering new nuclear power plants and building small modular reactors, including four 300-megawatt units at Darlington Nuclear Generating Station, the institute would like to see their designs incorporate waste heat reuse.

“In Ontario, the heat rejected from nuclear power plants is quite a bit greater than the heat required for heating with natural gas in the whole province,” said Michael Wiggin, a Boltzmann Institute director who is also leading the Ontario Society of Professional Engineers’ thermal energy advocacy. “So there’s an enormous possibility to use the heat from these power plants to heat cities.”

Waste heat can flip conventional narratives on their head. Data centres today are maligned for their energy needs. Yet what if their waste heat was put to beneficial use? 

That’s the objective in Lansing, Michigan, where Deep Green, a London-based company, has proposed a 24-megawatt, US $120-million data centre project that would transfer its waste heat into a district heating system run by the Lansing Board of Water and Light, a water and power provider. The Lansing City Council is set to vote on the project on April 6.

“Previously, we didn’t consider heat as an asset because we didn’t need to,” Mark Lee, CEO of Deep Green, wrote in a January 2026 blog post. “There was an abundance of power, cheap energy and less awareness of environmental impact. That’s changing: electricity prices are high, grids are congested and there’s pressure to meet net-zero and [environmental, social and governance] targets.”

Barriers to entry

Even with these first steps, energy experts agree that North America, as a whole, is playing catch-up. Scandinavian countries have been reusing waste heat for decades. Stockholm has a 3,000-kilometre district energy pipe network that serves 800,000 residents and more than 90 per cent of the city’s buildings. More than 30 data centres feed waste heat into the system. In Oslo, sewer thermal provided nearly 7 per cent of the energy for the city’s district heating system in 2025. As a whole, the system provides 30 per cent of Oslo’s heating and hot water demand. China, a more recent entrant in the market, has developed world-champion projects in Qingdao and elsewhere.

Committed cities and governments can reach scale quickly. “The Chinese had nothing hardly in the early ’90s, now they’ve got perhaps the most district heating installed capacity in the world,” Wiggin said.

Rapid growth in waste-heat recovery will not happen in the Great Lakes region on its own. Without policy signals, electric companies, data centre operators and water utilities don’t have the incentives to innovate and co-operate, Kohl said. And for waste heat, collaboration is the key to success.

What are those policy signals? Gaalswyk focused on carrots: tax breaks for companies that install heat recovery systems and a quicker permitting process for those that incorporate efficiency measures.

Wiggin, by contrast, outlined the sticks. A tax on waste heat. State or provincial efficiency standards.

Kohl mentioned both measures. Massachusetts, he noted, set aside state funds for waste-heat recovery feasibility studies. New York, meanwhile, passed a law in 2022 to develop a regulatory framework for thermal energy networks. The law requires the largest investor-owned utilities to submit pilot projects for development.

Those in the district energy industry see waste heat as a massive opportunity, one that begins in the early stages of project development, whether it’s a data centre or a nuclear power station. Incorporating waste-heat recovery into a project’s initial design is easier than retrofitting the facility in the future.

“Our thesis is data centre projects that are bringing additional layers of community benefit to communities will find more success in building trust and gaining the necessary social licence to operate,” Gaalswyk said. “A really important aspect of that is heat recovery, free heat. Again, it’s not a technology issue. We have the heat pumps, we have the industry that can design heat offtake. It’s a matter of figuring out how to get a diverse stakeholder group to work together to realize these benefits in tandem.”

The Narwhal’s reporters are telling environment stories you won’t read about anywhere else. Stay in the loop by signing up for our free weekly dose of independent journalism.

Summary

• There have been significant policy changes related to renewables in Alberta — including a seven-month moratorium on clean energy projects in 2023.
• There is a considerable decline in the number of renewable projects that are moving through the regulatory process in recent years.
• One report showed 44 per cent of renewable projects were cancelled between 2023 and 2025, representing enough power to supply the entire province. That analysis also shows a 32 per cent increase in proposed natural gas projects.

We’re trying out staff-written summaries. Did you find this useful? YesNo

According to some, the state of renewable power investment in Alberta is dire. According to the government, the province continues to be a leader.

Analysts point to investments falling off a cliff, while the Alberta government insists companies are still lining up to build new solar and wind projects in the province. 

Sooo, what’s really happening?

There’s no doubt investment has declined significantly since the provincial government first instituted a seven-month moratorium on renewable projects, followed by stiff new regulations and changes to the electricity market. 

The real question is just how precipitous the drop is and whether it signals a long-term trend or a short-term blip. 

Let’s dig in. 

So, wait, what did the government do to impact investment in renewables in Alberta?

To recap: in 2023, the Alberta government surprised just about everyone by declaring a moratorium on all new renewable energy projects for seven months. At the end of that moratorium, it introduced new restrictions on where renewable energy projects could be built and new regulations on those projects (you might remember the government declaring no wind turbines could block what it dubbed “pristine viewscapes,” for example). Last year, the government introduced new rules on building transmission lines that could disproportionately impact new and existing wind and solar projects. 

In the wake of all these changes, investments in renewables have declined significantly. 

That’s a marked change after years of surging investments that made Alberta the leader in renewable development in Canada over the past five years. 

Unlike all other Canadian provinces, Alberta has what’s known as a market-based electricity system. In Alberta, the government sets policy, regulators implement those directions and private investors, well, invest. Or they don’t.

What does the data on new renewable energy projects show?

While there are different ways to interpret some of the data, the picture is getting clearer and it points to a significant drop in renewables in Alberta. 

One measure is to look at the number of renewable projects that are moving through the regulatory process and listed by the provincial grid operator, the Alberta Electric System Operator. Essentially, proponents of the projects on the list have expressed interest in connecting to the grid. Maybe.

Projects on the list don’t always proceed, and many are in the early stages. But even so, the list is indicative of a change. 

Using the month of March as an example, there is a considerable decline.

In March of 2023, there were 179 wind and solar projects on that list. And while there was a slight increase in 2024, as the impacts of the regulations and the moratorium settled in, the figures dropped to 130 in 2025 and then plummeted to 60 in March 2026.

Of those 60 projects currently on the list, 41 applied before the renewable moratorium.  

Wind projects have seen the greatest decline, with eight currently active on the grid operator’s list — two of which were pitched after the moratorium. 

In an emailed statement, Nathan Neudorf, the minister of affordability and utilities, pointed to the approval of 16 renewable energy projects in 2025 by the Alberta Utilities Commission, which regulates electricity generation facilities.

Project approvals by the regulator have ranged from 12 in 2023 to 24 in 2024, but even those approvals are not indicative of projects being built. Several of the projects approved in both 2024 and 2025 have since been cancelled by their developers. 

An analysis by the Pembina Institute shows 44 per cent of renewable projects were cancelled between 2023 and 2025, representing enough power to supply the entire province. That analysis also shows a 32 per cent increase in proposed natural gas projects. 

Another report from the institute says Alberta “added only 137 [megawatts] of solar and no wind or storage” in 2025, down from a high of more than two gigawatts in 2022. As a guide, one gigawatt of power could supply up to one million homes.

 What about investments in renewable energy projects?

It appears the private money that drives much of Alberta’s renewable development is drying up.A recent report by Business Renewables Centre-Canada says the deals the organization facilitates between companies looking to buy renewable power and renewable developers, known as power purchase agreements, have declined. 

Power purchase agreements could mean a big company signs a deal to buy power from a renewable energy project, like Amazon did with the largest solar farm in Canada in 2021. That type of deal was a boon for the renewables industry.

But new corporate deals all but evaporated in Alberta in 2025, declining by 99 per cent compared to 2023, according to the report. 

Wind generation has been particularly impacted, according to the report, with no new projects announced in 2025. The most recent active project listed by the grid operator is from October 2024. 

Neudorf’s office did not respond to questions emailed by The Narwhal asking about the government’s view on declining investment in renewables and its specific concerns regarding the Business Renewables Centre-Canada report. Instead, a spokesperson sent a statement attributed to the minister. 

“The report provides a misleading characterization of the renewables sector in Alberta,” reads the statement. “In recent years, Alberta has led Canada in new renewable energy development, representing more than 85 per cent of Canada’s growth.”

The Business Renewables Centre-Canada report shows that, at least in terms of those power purchase agreements, that momentum has ceased. Nova Scotia was the top spot for those contracts in 2025. 

Where Alberta is doing well, according to the report, is attracting storage projects, with considerable growth in batteries, which can help smooth the intermittent nature of renewables and alleviate some of the challenges for wind and solar projects introduced with the province’s new transmission rules. 

So why is there any confusion about the state of the renewables sector in Alberta?

Renewable projects generally represent significant investments and involve years of planning and consultation prior to construction. In short, it can take a long time for the full impacts of regulatory and policy changes to make their way through the system. 

Almost three years since the moratorium, the impacts are starting to show up in the form of less investment and fewer projects. 

When the minister points to Alberta leading renewable growth “in recent years,” he focuses on a surge in investment from 2020 to 2023, not on what’s happening now. 

There are also projects that continue to be built and the government can point to those as an indication of continued investment. Depending on the region of the province and the specific location of a project, solar and wind projects can still make sense, particularly when paired with storage. 

But there are also continued headwinds.

For one, market reforms introduced by the grid operator on behalf of the provincial government have also introduced considerable uncertainty for investors looking to build projects, renewable or otherwise.

Then there are the new rules regarding transmission line connections that could make it too expensive for some renewable projects to be built, or continue to operate.

And the government has also made changes to its industrial carbon price and is currently negotiating that pricing with the federal government as part of its memorandum of understanding around a proposed new pipeline to the West Coast. 

All of those factors could impact investments in renewable energy generation over the short term and, potentially, for years to come.

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This story is part of Generating Futures, a series from The Narwhal exploring clean energy sovereignty among B.C. First Nations.

Summary

• West Moberly First Nations has limited access to fresh foods, due to long supply chains, cold winters and environmental contamination that has made many traditional foods unsafe to eat.
• The First Nation believes a greenhouse could boost food security and food sovereignty, and plans to tap a geothermal reservoir — which holds scalding hot water buried deep underground — to heat it.
• Their geothermal project could be the first of its kind in the province, which boasts major geothermal opportunities but has no commercial-scale projects in operation.

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Moldy strawberries, wilted lettuce. A forlorn cauliflower pocked with brown. West Moberly First Nations Councillor Clarence Willson jokes that produce available in nearby stores is sometimes “compostable” before it hits the shelves.

That produce arrives by way of a very long supply chain, and their northeastern B.C. territory, a three-and-a-half hour drive northeast of Prince George, is often the end of the line. And thanks to the compounding effects of hydro dams, seismic lines for oil and gas, forestry and coal mines, traditional foods the nation has long harvested or hunted have grown increasingly scarce or unsafe to eat.  

“We have to start looking at how we sustain ourselves,” Chief Roland Willson of West Moberly First Nations says. “Not just West Moberly, but the people in the northeast.”

“The idea of the greenhouse is, to me, where I think we have to go.” 

Growing fresh food year-round in greenhouses could improve food security in the community and across the region, but it would take a lot of energy, too. Fortunately, the First Nation has a serendipitous asset buried deep underground: scalding hot, salty water. 

Thanks to B.C.’s lively tectonic faults, it has an abundance of this underground water, a key ingredient in what’s known as conventional geothermal energy. Hot water is pumped to the surface, using tools like turbines and heat exchangers to generate renewable electricity or direct heat. Elsewhere, companies are working to design so-called “unconventional” geothermal technologies to extract the earth’s heat from places without such reservoirs, but the drilling required makes it much more costly. B.C.’s geothermal opportunities, in other words, are a relatively low-hanging fruit — one that could literally yield fruit, and other fair-weather crops like tomatoes and peppers, even in winter’s subzero temperatures. 

“British Columbia has a world-class geothermal resource,” says Emily Smejkal, a geologist and policy lead for the Cascade Institute’s geothermal energy office. “We’re just not using it.”

Geothermal energy supplies consistent power, making it similar to the hydro dams and natural gas B.C. currently relies on.   

If the nation’s project succeeds, the West Moberly direct heat geothermal greenhouse project would be the first of its kind in Canada. Such innovation brings risks to its trailblazers, but Clarence, a longtime lead on the geothermal project, says the potential outcomes are worth it.

“When we learned about this geothermal availability, it fit right into our idea of food sovereignty,” he says. 

“We want to be in control of our supply of food, knowing what goes into it and what’s good about it.”

Fragmented food systems have impacted food security, territory

Fresh food used to be abundant in West Moberly’s territory.

“If you needed meat, you’d go to the mountains and get yourself a caribou,” Roland says. Fish came easily, too: rivers were once plentiful enough that you could catch them by hand. The nation’s members travelled throughout their territory with the seasons, maintaining balance and keeping their impacts in check.  

Over a century ago, Canada signed Treaty 8 which promised signatory First Nations would retain the right to hunt and fish as they always had.

But that’s not what happened. 

To supercharge resource extraction in the north, former premier W.A.C. Bennett dammed the Peace River, bisecting the once-expansive migration of transient caribou that fortified the residential herds. “Caribou that roamed throughout the territory got fragmented down into these small, little pockets,” Roland says, “and then wolves came in.”

Wolves and other predators made use of roads — and seismic and power lines etched across the territory, offering them an easy-access escalator to the caribou’s mountain hideaways. As logging and mining further depleted caribou habitat, the herds plummeted. In 2014, the nation launched a breeding pen program with the Saulteau First Nations, and yet herds remain in critical condition.

Other foods suffered, too: moose and elk populations fell, thanks in part to habitat loss and to new hunting pressure in the caribou’s absence. Berries throughout the territory were sprayed with glyphosate, a chemical now deemed “probably carcinogenic” by the World Health Organization. 

For decades, fish remained relatively plentiful — and critical to diminishing food security. 

Every year in May, Clarence and his family would gather at a special spot along the Crooked River to fish for char, sometimes setting up barbecues to cook by the river as they worked. But worries began to surface, thanks in part to a sign in the Hudson’s Hope post office warning of elevated mercury levels in the Williston Reservoir. The nation knew that fish travelled through the reservoir, and initiated a study in 2015 to determine whether they were safe to eat. 

“I was in tears when we got the results back, because I knew my family had been eating those fish for years,” Clarence says. 

Ninety-eight percent of the samples had mercury concentrations above B.C.’s health guidelines. Women of childbearing age could safely eat only a Hershey’s Kiss worth of fish every other day.

Before it was flooded, the community learned that BC Hydro’s new dam project, Site C, would bring mercury contamination closer to home. The reservoir is downstream of the Moberly River, which threads through the nation’s territory and flows into Moberly Lake directly facing their community. Just as the Crooked River carried the reservoir’s toxins upstream, the Moberly River is poised to do the same. “A lot of us eat fish directly out of the lake,” Clarence says.

“They went ahead with Site C with the full knowledge that it was going to do the same thing there.”

Clarence added that selenium pollution from nearby coal mines also impacts the region’s watersheds. “All the river networks in our region are affected by something,” he says.

With many traditional food sources depleted or contaminated, West Moberly has taken action over the years to regain access to fresh foods. The nation funded community members to build garden beds, but short growing seasons mean they offer limited respite to a year-round problem. 

A greenhouse could bridge the seasons, but West Moberly First Nations has no natural gas service in its community. And according to Michael Keefer, president of the ecological restoration consultancy Keefer Ecological, the added costs of using electricity to power a greenhouse year-round would make the prospect a non-starter. 

“It’s very energy-intensive to heat a greenhouse,” he says.

That is, unless the nation has another energy source to draw from. 

Energy from an ancient sea-floor

Hundreds of millions of years ago, the earth’s supercontinent broke up along the border of northeastern B.C. and Alberta, turning it — and what would become West Moberly’s traditional territory — into a shallow tropical sea, populated by giant reptilefish.

Eventually, sediment and rock covered it over, leaving little holes underground where that sea-floor had been. 

“If that buried sea-floor doesn’t hold air anymore, it holds salty water or oil or gas,” Smejkal says. Known as “brine,” that water is more plentiful than its fossil fuel cohabitants. “Oil and gas are hard to find,” Smejkal says. “Water is actually pretty easy.”

In addition to that ancient sea-floor, B.C.’s geothermal potential also abounds beneath the chains of volcanoes tracing its coast. There, hot water comes from rain that trickles underground through porous rocks, heated by the volcanoes’ pimple-like proximity to the earth’s molten core.

Some B.C. buildings use a geothermal-lite technique called “geoexchange” to supplement their energy needs by heating water in shallow underground pipes, but to date no projects have successfully tapped the potential of deep-buried water. 

Glen Clark, chair of the BC Hydro board, told The Narwhal he thinks B.C.’s lacklustre geothermal industry is due in part to an abundance of cheap hydropower and gas. “You’ve got these inexpensive fuel sources that have impaired, in a way, the kind of experimentation you’d have if the price were higher,” he says. But Clark says geothermal is “a really, really important resource,” that could play a key role in B.C.’s energy system in the future. 

Producing electricity from underground water is also finicky: it needs to be super hot, at around 120 C. But industrial sites like greenhouses can easily skip the electricity step, using geothermal heat directly in their operations, creating a less risky project. When West Moberly realized the heat in their geothermal resource was ideal for greenhouse conditions, it seemed like an obvious conclusion, Clarence says. 

“That’s been a topic we’ve discussed for years.” 

Next phase of geothermal project is risky, requires substantial new funding

If all goes as planned, West Moberly’s geothermal greenhouse will bring fresh produce and fish back to the territory. 

Using a system known as aquaponics, the nation plans to raise fish in tanks and use their waste to fertilize vegetables in the greenhouse, cutting down on or eliminating the use of synthetic fertilizers. 

“The waste from the fish is excellent fertilizer for the greenhouse products,” Clarence says. “They work together very well.” 

So far, the nation plans to raise fish like tilapia alongside produce like tomatoes, strawberries, greens and peppers in a 40,000-square-foot greenhouse — enough to provide food for its members and surrounding communities. Keefer is working with the nation to develop a business plan, including reaching out to local grocery stores. He’s confident their products will be in high demand — as long as everything goes according to plan. 

Even though the project is designed to produce a more forgiving form of direct heat, the enterprise still brings risk. “For our project, flow is our big worry,” Ben Lee says. He’s an operations engineer and heat transfer specialist with Calgary-based company Raven Thermal Services, which is helping to design the geothermal project with the nation. If the company doesn’t find enough water in the reservoir it targets, it won’t be able to bring enough heat to the surface, and may need to drill farther into the rock to access it, upping the project’s costs. 

Lee says they chose to locate the project next to an abandoned oil and gas well near the community, which can serve as a pre-drilled test plot to assess subsurface conditions they might encounter. This is among the many conservative decisions made, Lee says, to reduce risks inherent in the project. “When you’re talking about a community-based project, risk management becomes absolutely critical.”

Having received early feasibility funding from federal and provincial governments, the project now requires substantial new funding to take on the next big step of drilling the hole to determine how much water is there. 

In countries where geothermal energy has boomed, Smejkal says that risk-taking has often been a shared enterprise. For example, in what’s known as the “glass city” — the Westland region of the Netherlands — geothermal-powered greenhouses produce food for distribution across Europe. There, governments agreed to help compensate for the cost difference between geothermal power and natural gas, and offered an insurance program to reduce risks for geothermal projects. By removing the consumer carbon tax and failing to provide consistent support for geothermal energy, Smejkal worries Canada is heading in the opposite direction. 

Clark sees a role for the utility to advance geothermal in the province and help to reduce risks for developers. But, he warns, it faces competing demands for funds and time, including major substation investments to replace aging infrastructure. He says he wasn’t aware of West Moberly’s geothermal greenhouse project, but added that the utility generally enters into equity agreements with First Nations to share ownership of the energy system, like transmission lines, “as opposed to more historic reparations.” He added that he didn’t know enough about the mercury issues related to Site C to comment on them.

Speaking to The Narwhal from his home alongside Moberly Lake, Clarence says those responsible for the community’s collapsing food system are indebted to help. 

 “Some of these people that are poisoning our food supply, they should help us with trying to have good food here,” he says.

Generating Futures is made possible with support from the Real Estate Foundation of BC. As per The Narwhal’s editorial independence policy, no foundation or outside organization has editorial input into our stories.

Updated on March 9, 2026, at 6:53 a.m. PT: This article was updated because a previous version incorrectly attributed a quotation to Roland Willson in a caption. The quotation has been deleted from the caption, but remains unchanged in the story’s main text, where it is correctly attributed to Clarence Willson.

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Summary

• Despite the Government of Canada’s requirement for provinces and territories to phase out coal-fired power generation by 2030, Saskatchewan is refurbishing its coal plants.
• Federal Environment Minister Julie Dabrusin has the power to intervene and stop Saskatchewan’s pursuit of coal, but her office would not confirm if she’ll do that.
• Many have argued there are cleaner and more economical options than emissions-heavy coal for generating electricity.

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Federal Environment Minister Julie Dabrusin will work with Saskatchewan to “ensure” it follows the law, her office reiterated, as the province pushes to keep its coal plants open past Canada’s deadline. But when asked if she would intervene to stop the province’s continued reliance on coal-fired electricity, Dabrusin’s office was mum.

Saskatchewan’s decision to extend the life of its coal plants has put it on a collision course with federal rules to phase them out nationwide by Dec. 31, 2029. The province said last year it will spend $900 million refurbishing its coal plants for “years to come.” As of Feb. 26, the provincial Crown corporation SaskPower reported it was relying on 76 per cent fossil fuels for its electricity supply — 28 per cent coal and 48 per cent natural gas.

Canada wants to phase out coal plants, which burn thermal coal to generate electricity, because they’re the highest-emitting sources of carbon pollution and air pollutants in the country. Not only do they emit carbon dioxide, which is driving climate change, they can also emit nitrogen dioxide, sulphur dioxide and mercury, which are all on Canada’s toxic substances list and have been linked with respiratory diseases, cardiovascular diseases and acid rain. Ontario’s decision to decommission coal plants followed findings that this pollution was costing the province’s health care system $1 billion per year.

But Saskatchewan Crown Investments Corporation Minister Jeremy Harrison has said the province will “not comply” with federal Clean Electricity Regulations, which were finalized in December 2024 and put limits on emissions from fossil fuel electricity generation starting in 2035. Harrison has said they would create a financial burden on the province and lead to job losses. Both the regulations to phase out coal power and to limit power plant emissions are part of the Canadian Environmental Protection Act, which regulates toxic substances and was upheld as constitutional by the Supreme Court of Canada. Dabrusin, as the minister responsible for the Canadian Environmental Protection Act, has the power to intervene when a party is about to violate the law or its regulations.

She can seek an injunction, for example, to prevent a violation, and if a government agency is ignoring an injunction, she can seek a court order to comply or a contempt of court ruling, among other options.

The Narwhal asked the minister’s office on Feb. 20 if she plans on using the powers of the Canadian Environmental Protection Act to intervene and ensure either or both of the two regulations are followed.

Dabrusin’s press secretary Keean Nembhard pointed to a statement from the minister posted on the social network X six months earlier, which said phasing out coal was essential for cutting emissions, protecting clean air, supporting public health and meeting climate commitments. 

The post reiterated that federal regulations “require the phaseout of all unabated coal-fired power plants by December 31, 2029.” Unabated means emissions that are released into the atmosphere without any technology like carbon capture.

“We will continue to work with provinces and territories to ensure that all legal requirements and climate commitments are met, while supporting a reliable and affordable transition to clean energy,” the minister stated.

Nembhard also sent a statement to The Narwhal featuring the same quotes.

The federal and Saskatchewan governments signed a deal in 2024 that lets the province temporarily avoid the coal phase-out rules, but it expires at the end of this year.

It says Saskatchewan agreed to have a generating capacity made up of at least 30 per cent non-emitting electricity sources by the end of 2024, 34 per cent by 2027 and 40 per cent by 2030. According to SaskPower figures from June 2025, it appears to have met the 2027 target for total capacity, but how much those different sources contribute to the grid fluctuates regularly.

Saskatchewan Environmental Society will be ‘encouraging’ Dabrusin to intervene

Canada and the United Kingdom co-launched the Powering Past Coal Alliance in 2017 with the goal of phasing out coal power worldwide. At the United Nations climate summit in November 2025, Dabrusin said the “coal-to-clean transition is inevitable.”

In January, a Saskatchewan court dismissed a citizen-led legal challenge against the coal-power extension plan, saying it was a matter of government policy.

The applicants — Citizens for Public Justice, the Saskatchewan Environmental Society and three individuals — have filed a notice of appeal. They say the province’s decision, which could see its coal plants still active into the 2040s, violates federal law and was made without sufficient public consultation. 

“We’re going to be encouraging the federal minister to consider getting involved in objecting to the Government of Saskatchewan’s decision to keep its coal-fired power plants running,” Peter Prebble, a member of the board of directors of the Saskatchewan Environmental Society, said in an interview.

“It would be helpful if the federal minister actually intervened and said to Saskatchewan, ‘You can’t do this,’ because she does have that authority.”

Saskatchewan law claims province has ‘autonomy’ over carbon pollution controls

The Saskatchewan legislature passed the Saskatchewan First Act in 2023, which claims the province has “autonomy” over several areas including electricity generation, and any conditions affecting it, such as environmental standards and the regulation of greenhouse gas emissions. 

The province established a tribunal under that law to examine the federal clean electricity rules. That tribunal produced a report claiming the rules would be a massive financial burden. 

Saskatchewan’s Harrison then used the tribunal’s findings to claim the federal rules were “unconstitutional,” “unaffordable” and “unachievable” and to declare that the province “will not comply with them.”

In 2025, he wrote a letter to SaskPower saying the Government of Saskatchewan had made the decision to extend the life of its coal power plants as a “bridge” to building a new fleet of nuclear power plants. 

“The certainty and security of coal means that it will continue as a pillar of our electrical generation system as we bridge to a nuclear future powered by Saskatchewan uranium,” Harrison wrote in the letter.

That nuclear future will not come until the mid-2030s, and perhaps later. The Crown corporation is planning for a small modular reactor to be built around that time. It also announced in January it was just beginning another process to evaluate large nuclear plants, which take longer to build.

The Narwhal reached out to Harrison’s office and SaskPower but did not receive a response by publication time.

The many alternatives to continuing to rely on coal

Prebble argued there are better and cheaper alternatives to extending the life of coal power. The province could upgrade its grid connections with Manitoba to import more hydropower, generated from dams on the province’s rivers, he said, or invest in electricity efficiency and conservation. He also advocates for boosting renewable capacity in Saskatchewan.

“We’ve got the best solar resource in the country, and we’re barely using it. Less than one per cent of our electricity is coming from solar,” he said. 

“We’ve got an incredible wind resource. Energy storage technologies are improving. There’s lots of potential for co-generation of electricity,” he added. “There were lots of other options.”

The Canada Energy Regulator estimates southern Saskatchewan has some of the highest solar photovoltaic potential in Canada as well as some of the highest wind energy potential.

Prebble also noted the United Nations has asked developed countries to phase out coal power by 2030 and developing countries to follow suit in 2040.

“It’s pretty incredible that a wealthy jurisdiction like Saskatchewan would say that it’s going to keep running its plants, knowing all the dangerous consequences that are associated with climate change,” he said.

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A citizen-led climate justice challenge to the Saskatchewan government’s plan to continue using coal power failed when a court sided with the province last month.

Last summer, the provincial government and SaskPower laid out a plan to continue using coal-fired generation despite federal regulations aimed at phasing out the polluting power source by 2030. Residents and citizen groups responded by filing a judicial challenge, arguing the province’s decision is “unreasonable” and should be reviewed by the courts due to a lack of public consultation, a disregard for Canadian and international law and potential implications on Canadian Charter rights.

A Court of King’s Bench justice sided with the province and dismissed the application on Jan. 12, on the grounds that the court’s role is not to dictate climate policy or direct the day-to-day policy of a government.

The Saskatchewan government said in an emailed statement sent to Canada’s National Observer it is “pleased” with the court’s ruling, which “determined that the issue is essentially one of government policy and, as such, is not for the courts to decide.”

The applicants (the Saskatchewan Environmental Society, Citizens for Public Justice and three individuals from Saskatchewan and Manitoba) say a judicial review is the only means of holding the government to account for its “unprecedented” decision to continue burning coal and ensuring evidence of the government’s decision-making is “justified, transparent, and intelligible,” said Glenn Wright, the lawyer representing the applicants, in a Jan. 16 press release. 

“Saskatchewan has been planning to phase out coal for 15 years, and the coal decision is a marked departure from that long-standing objective. We believe that a near billion-dollar administrative decision to double down on the most polluting form of energy generation — a decision which, we believe, violates the rule of law — is something that the courts can and should review.”

After the lower court disagreed with them, the applicants said they are in discussion with counsel and are considering their options, including a potential appeal of the decision to the Saskatchewan Court of Appeal.

Coal is the dirtiest fossil fuel and produces more planet-warming carbon dioxide when burned than either oil or gas. 

The province’s Saskatchewan First Energy Security Strategy and Supply Plan lays out its strategy to use coal as a bridge to nuclear energy but does not contain any cost estimates, just a demand that the federal government pay for 75 per cent of its first nuclear reactor.

It is going to cost the province an estimated $900 million over four years to extend the lives of its coal power plants. 

“The environmental and health risks posed by extending coal use for many more years remain just as serious as ever,” said Margret Asmuss, president of the Saskatchewan Environmental Society, in a press release. “Saskatchewan residents deserve responsible, evidence-based energy planning that protects people, communities, the economy and the environment.”

The group noted the $900 million for coal plant refurbishment could — and should — be going to up-and-coming technology and industries such as battery storage and renewables, but instead the province is choosing to delay these opportunities by doubling down on coal. 

Ontario was the first province to phase out coal-fired electricity, under Premier Kathleen Wynne in 2014. Last summer, Alberta transitioned its last coal plant to natural gas to complete the coal phase-out. New Brunswick, Nova Scotia and Saskatchewan still use coal-fired electricity.

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Last year’s sweltering summer strained the power grid as Ontarians struggled to keep cool.

But the province had a powerful ace up its sleeve.

Stored inside 278 giant lithium-ion batteries — each the size of a tractor-trailer — in rural Haldimand County was enough energy to instantly power tens of thousands of homes when temperature spiked and electricity demand surged.

“Some of those really hot days we had this past summer, Oneida was key to keeping the lights on,” said Scott Matthews, vice-president of projects with energy storage developer NRStor Inc., a partner in the Oneida Energy Storage Project along with majority owner Northland Power, Aecon, Six Nations of the Grand River Development Corporation and the Mississaugas of the Credit Business Corporation.

The 10-acre, $700-million battery farm near Jarvis, Ont., is the largest operation of its kind in Canada, able to return 250 megawatts of electricity to the grid each hour for four hours.

And while gas plants are slow to come online, power from batteries can flow at the press of a button. “This is just immediately available, any time,” Matthews told The Hamilton Spectator.

Having that flexibility helps, said a spokesperson for Ontario’s Independent Electricity System Operator, which manages the province’s power grid.

“The province faced the highest peak electricity demand since 2013 during this summer’s heat waves, and Oneida helped meet this demand by providing over 1,000 megawatt hours of energy,” spokesperson Michael Dodsworth told The Spectator.

Noting Oneida was the first large-scale battery storage facility to connect directly to Ontario’s power grid, Dodsworth said the project “represents a major step forward in making our grid more flexible and resilient at lowest cost.”

With nuclear reactors having to run all night as demand dips, Ontario is sometimes forced to pay cross-border consumers to absorb excess power from the grid. Storing that energy for later use at peak times makes more sense than giving it away, Matthews said.

And since Oneida also stores energy produced at off-peak hours by renewable sources like wind and solar, it is a cleaner power source than emission-heavy gas plants, he added.

That success has helped pave the way for new battery projects — including three more applications currently under review for Norfolk County.

Trio of projects pitched for Norfolk County in southern Ontario

When it came online last May, Oneida more than doubled the province’s energy storage capacity. With electricity usage projected to skyrocket in the coming decades, Queen’s Park wants to expand capacity in a hurry, and three Norfolk-area projects are under review by Ontario’s electricity system operator.

Skyline Clean Energy, a newcomer on the energy storage scene, wants to install 65 lithium-ion phosphate batteries the size of shipping containers on two acres of a solar farm the company owns outside Simcoe, Ont. The humming sound produced by dozens of batteries feeding 30 megawatts of power to Hydro One’s distribution grid would be no louder than a library, Skyline’s director of asset management, Matt Kennedy, told Norfolk councillors at a presentation in November. Noting this battery farm would fall within Simcoe’s wellhead protection area, Coun. Doug Brunton raised concerns about contaminants leaking into the town’s water supply should the batteries catch fire. Kennedy promised prompt soil testing and remediation should that happen.Norfolk Resilient Generation Inc. is looking to produce up to 15 megawatts by burning natural gas in five reciprocating engines installed in shipping containers on a livestock farm outside Simcoe. The power would be stored on-site until needed on the grid, while heat from the engines would warm a hog nursery barn on the farm.

NRStor, after being turned down by the system operator for a 2023 project proposal in Simcoe, pitched a larger project last November that would store 150 megawatts on 20 acres of industrial land in the municipality. The Simcoe Battery Project would provide 1,200 megawatt hours to the Hydro One grid over an eight-hour period. The same Indigenous organizations that partnered with NRStor for the Oneida project would have a financial stake in this venture.

Norfolk’s economic development department says “energy storage technology represents a strategic infrastructure investment that supports energy reliability.” But some councillors have expressed concerns about noise and the risk of the lithium-ion batteries catching fire.

At a council meeting last year, members heard each temperature-controlled battery unit comes with a built-in fire suppression system, and the companies would pay for additional training for Norfolk’s volunteer fire department.

Large-scale battery storage facilities pose a different risk than smaller lithium-ion batteries found in scooters, e-bikes and the like, Deputy Fire Chief James Robertson told The Spectator in an email.

“Those types of installations are highly regulated and typically include built-in fire suppression and safety systems,” he said. “This is quite different from smaller hobby-related batteries.”

All three applicants have secured the municipality’s endorsement, which is required by the system operator. Each company offered Norfolk a sweetener in the form of annual financial contributions to the county’s coffers.

Norfolk wants to get $1,500 per kilowatt hour per year from any successful bidder, which would make Skyline’s contribution to the municipality around $900,000 over the 20-year life of the project, while NRStor’s larger facility could generate $225,000 annually for the municipality.

The system operator is expected to issue project approvals by the middle of June. The earliest any of the proposed facilities would connect to the grid is 2028.

Oneida ‘proved the hypothesis’

NRStor’s director of project development, Fariha Husain, told The Spectator none of this momentum would be happening had Oneida not proved it is possible — and profitable — to store power.

“The Oneida project basically opened the door to all these procurements,” she said.

The project is already exceeding NRStor’s revenue projections, Matthews added, which means money is flowing into Six Nations and Mississaugas of the Credit to fund schools and other local projects.

“You’re actually seeing those benefits roll into the community, which is amazing,” he said.

In a statement to The Spectator, Energy Minister Stephen Lecce also praised the inclusion of the Six Nations of the Grand River Development Corporation and the Mississaugas of the Credit Business Corporation as partners in Oneida, which he noted came in “ahead of schedule and under budget.”

“Collaboration between government, Indigenous partners and the private sector is the model that will further propel our economy forward with one of the cleanest electricity grids in the world,” Lecce said.

Oneida will not be the largest battery storage facility in Canada for long. A 411-megawatt project south of Ottawa in Edwardsburgh Cardinal is expected to come online next year, while Quebec-based energy company Boralex is building a 300-megawatt facility near Hagersville in Haldimand.

The Hagersville project has faced some opposition from residents, but Haldimand council has embraced the idea of battery storage, authorizing municipal staff to automatically issue letters of support to proponents who meet county-established criteria.

A 211-megawatt battery farm northeast of Jarvis is also under review in Haldimand, with three smaller projects in the public engagement stage.

Ontario is expanding the power grid even as Prime Minister Mark Carney suspended a Trudeau-era mandate last September that would have required 20 per cent of new vehicles sold in Canada to be zero-emission.

But Matthews said a slowdown in the sale of electric vehicles will not lessen Ontario’s “staggering” need for power.

Husain agreed, predicting the “electrification” of home heating systems such as heat pumps will continue to drive demand for low-cost electricity produced from renewable resources.

“We think electrification is key to meeting our climate goals, and that’s what this all stems from,” she said.

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This story is part of Generating Futures, a series from The Narwhal exploring clean energy sovereignty among B.C. First Nations.

On the northwestern corner of Vancouver Island, wind and storms will often rip through Quatsino Sound. The wild west coast weather means Quatsino First Nation experiences frequent power outages.

There are few ways in and out of the community, roughly a six-hour drive northwest from Victoria. If they’re blocked by rough weather, “we’re closed off from society,” Quatsino member Kara Wilson says. 

But that weather has also created opportunities. A wind farm opened in 2013, which the nation has partial ownership in, and Quatsino is working to build more renewable energy infrastructure. It is on the cusp of completing the third and final phase of its 150-kilowatt solar project in the spring.

But Quatsino isn’t stopping there — it is pushing to deploy a tidal energy system later this year, which would be one of the first pilot projects of that technology on the west coast, Wilson says.

Through its energy projects, the nation aims to provide reliable power at lower costs to its population of roughly 600 people, along with bringing jobs and independence. Quatsino is pursuing these renewable projects so members can “have that comfort at home that they’re always going to have energy no matter what,” Wilson says.

Wilson is the energy champion for Quatsino First Nation, a title that means she leads conversations about the nation’s energy projects with business partners  and community members. It also means she’s seen all the funding hurdles, manufacturing interruptions and bureaucratic hiccups that can make it hard for small, remote communities to launch their own projects. But after pushing through those challenges, she says Quatsino hopes to share its successes to show other communities “it is possible.”

Challenges to launching small, local energy projects

Quatsino completed the first two phases of its solar project in the first half of 2025, working with Canadian company Shift Energy Group to install solar panels and battery storage at the nation’s daycare and administration building. The third phase, providing power to the nation’s school, was delayed due to U.S. tariffs and a broad public service strike in B.C. late last year.

The efforts go back to 2017, when Quatsino began working with Barkley Project Group, a sustainable energy consultancy on Vancouver Island, to develop a community energy plan. Community members identified lowering energy costs, improving efficiency and exploring renewables as priorities. In 2020, the nation began installing heat pumps in homes, and seeking funding for other projects, like its solar installations.

Wilson hopes these projects will also help create good jobs in construction and maintenance close to home for Quatsino members and people in the nearby community of Port Hardy, B.C.

“A lot of our people are having to relocate because of a lack of work here and the cost of living,” she explains.

But creating a local energy source, just big enough to meet a remote community’s needs, can be a tough sell for support and funding, she says. Most of BC Hydro’s calls for power — open application periods for renewable energy projects across the province —have been for larger projects, built to have extra energy to sell, versus small projects focused on bringing sustainable, resilient energy to remote communities. For example, the 2024 and 2025 calls for power required applications to have a minimum capacity of 40 megawatts — or 40,000 kilowatts — compared to the 150 kilowatts Quatsino’s solar panels will generate.

Many projects First Nations are trying to get off the ground are smaller than 40 megawatts. Wilson says the nation had been ready for a while to invest in smaller scale projects but it was hard to get support for those, and they had to wait until they were ready to take on something bigger.

These projects don’t provide the obvious economic impact of being able to sell excess energy, but they provide a relief to community members with lower energy bills.

“All across B.C., everybody everywhere is struggling with the ongoing rises with rent, with the basic essentials to do with having a roof over your family,” Wilson says. 

First Nations have ‘a central role’ in B.C.’s clean energy future: BC Hydro

Many First Nations across B.C. have ambitions to pursue renewable energy, but are hindered by a lack of capacity and funding opportunities. In response, the province has created new funds, and BC Hydro required 25 per cent Indigenous equity in applications to its 2024 and 2025 calls for power. 

In an emailed statement, BC Hydro said the 2024 call for power delivered majority First Nations ownership for almost every project it funded and up to $3 billion in equity ownership for First Nations, and the 2025 call “is also designed to ensure First Nations play a central role in the province’s clean energy future.”

BC Hydro said it’s also supporting smaller projects, partly by working with off-grid communities since 2019 to support them in designing and developing renewable energy to use less diesel, along with supporting other programs for microgrid and on-grid communities like the Community Energy Diesel Reduction program. 

The utility is focusing on “partnering with communities rather than building projects ourselves” and purchasing energy from the communities, the statement said.

As for personal consumption, BC Hydro said it has among the lowest electricity rates in North America, and that residential rates are third lowest and half of what Albertans pay. It said it has eliminated higher electricity rates for 14 off-grid communities, which are primarily First Nations. In 2024, it contributed $80 million to support lower income households, social housing and Indigenous communities in programs and rebates through its Energy Efficiency Plan.

Nation is pursuing energy cost savings and independence

Quatsino estimates the solar panels will annually save the nation over $18,000 annually through reduced BC Hydro usage by the daycare, administration building and school. 

“The way we got leadership on board was highlighting those estimated savings,” Wilson said, and the fact those savings could support “other programs that [they’re] wishing to either revitalize, restructure or start new.”

If these projects create jobs that can keep people in the community, Wilson hopes that will also give them more opportunity to connect with revitalizing cultural and traditional art practices within Quatsino — some of which may be supported and powered by the new energy sources.

The nation is hoping the solar power can supply its youth culture camp at the ancient village of Xwatis, also called Old Quatsino. It’s a significant cultural site where Quatsino people lived before they were relocated farther north to their current reserve.

The nation wants to diversify from hydroelectricity partly because people are concerned about its impacts, as it diverts water and can contribute to drought and hydrological issues, Wilson says.

To branch out into new forms of energy, Quatsino sourced funds from New Relationship Trust (which the B.C. government supports) and Natural Resources Canada. It also applied to B.C.’s First Nations Clean Energy Business Fund, which has allocated $1.49 million to 12 First Nations so far. Quatsino was also accepted with the Accelerating Community Energy Transformation initiative at University of Victoria.

Quatsino had also hoped to receive funds from the BC Hydro rebate program for solar panels and battery storage for Indigenous communities, but interest in the program was so great it had to pause intake of applications, including Quatsino’s.

Among B.C. First Nations, the momentum seems to be building. Last year, Ulkatcho First Nation broke ground on its solar project, while Nlaka’pamux launched its own in October. Another went online in December owned by Tll Yahda Energy, a partnership of Skidegate Band Council, Old Massett Village Council and the Council of the Haida Nation.

Quatsino’s broad energy sovereignty vision includes more than the solar project and tidal energy device. The nation is also exploring the feasibility of electrifying four fish farms. It’s also possible Quatsino could eventually take over majority ownership of the Cape Scott wind farm from the current majority owner, Engie.

In 2025, the nation also received funding from Island Coastal Economic Trust to partner with Ehattesaht, Ka:’yu:’k’t’h’/Che:k:tles7et’h’, Nuchatlaht and Mowachaht/Muchalaht First Nations to pursue a transmission line to the North Island to improve connection with the BC Hydro grid, ensuring more reliable power for communities.

Wilson says she takes immense pride in her role as energy champion and what the nation has accomplished so far. She was once intimidated by the technical details of these projects, but now, she’s the one breaking them down for community members.

“I emotionally got invested because I have two boys at home that I want to set the example for, about how they can become a leader and how even when you run into hiccups — that it’s still possible, as long as you keep pushing and don’t give up.”

Generating Futures is made possible with support from the Real Estate Foundation of BC. As per The Narwhal’s editorial independence policy, no foundation or outside organization has editorial input into our stories.

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Construction on the North Coast transmission line is not expected to start until later this year, but last week BC Hydro took “a key step toward securing a major customer” for its electricity: Ksi Lisims LNG.BC Hydro and Ksi Lisims LNG have signed a memorandum of understanding that “provides clarity on how and when BC Hydro will deliver as much as 600 megawatts of clean electricity to the proposed floating LNG facility,” according to the government’s press release. Energy Minister Adrian Dix hailed the agreement as a key step toward Ksi Lisims’ final investment decision, which is expected later this year.The details of the agreement will not be made public, a BC Hydro spokesperson told The Narwhal in an email, because it contains confidential information about Ksi Lisims.

The Ksi Lisims LNG project is expected to consume as much electricity as 250,000 B.C. homes use in a year. How BC Hydro plans to supply that power — and what it means for the broader grid — has not been disclosed. But a key piece is building the multibillion-dollar transmission line. In December, Dix signed a cabinet order outlining many of the terms BC Hydro and North Coast transmission line customers will operate under, including that the costs for the project be recouped via hydro rates.The most recent cost estimate for the first two phases of the North Coast transmission line is $6 billion, double BC Hydro’s initial $3-billion estimate. The third phase of the project, which will run high-voltage transmission lines north from Terrace, B.C., to Bob Quinn Lake near the Alaska border, has not yet been costed. B.C. is currently negotiating with the Canadian government to secure federal funding for the project.

The B.C. government estimates the projects served by the new transmission line could yield $950 million per year in revenue for the provincial and local governments and boost B.C.’s gross domestic product by “nearly $10 billion per year.” Ksi Lisims is “expected to attract nearly $30 billion in investment,” according to the province.

But in order to lock in those economic benefits, BC Hydro has to provide “cost certainty” to those potential new customers. If that means reducing the amount of money private companies would otherwise be expected to pay, BC Hydro will have to find other ways of recovering those costs.

“Rate payers are going to pay in the end because [these projects] are going to need so much electricity that supply is not going to be able to meet demand and prices are going to have to go up,” explained Andy Hira, a political science professor and director of the Clean Energy Research Group at Simon Fraser University. 

New contracts could let big projects off the hook for connection costs

The North Coast transmission line will primarily serve industrial customers, including mining projects and the Port of Prince Rupert. The B.C. government has not been shy about promoting the project as a boon for private companies it hopes will invest in the province.“This is the reliability companies can count on, every hour of every day,” Premier David Eby told a crowd at the Natural Resources Forum in Prince George, B.C., on Jan. 20. “Certainty that power will be there when companies need it. Certainty that it will be available at a predictable cost. That certainty is what turns proposals into final investment decisions.”

But here’s why that cost certainty could mean higher hydro costs for British Columbians. A cabinet order Dix signed in December could spare large North Coast power users from paying millions to hook into the power grid.

The order includes new contracts specifically for North Coast transmission line customers. One of those contracts deletes a handful of words from a decades-old contract called tariff supplement 6, which requires new industrial customers seeking more than 150 megawatts to pay the costs of generating and transmitting the power beyond that threshold.

“This was an important protection for other customers and was put in place in the 1990s after a negotiation overseen by the BC Utilities Commission,” Richard Mason, a former BC Utilities Commission member, told The Narwhal. “New large loads using the North Coast transmission line will almost certainly require BC Hydro to add new generation, raising the average cost for everyone.”The tweak in the new contracts seems to let large projects, like Ksi Lisims, seeking to connect to the North Coast transmission line off the hook for extra generation and transmission costs they would otherwise be required to pay.“In other words, new customers with large loads won’t have to contribute to any extra transmission or generation cost,” Mason said. “These costs will now be socialized across all BC Hydro’s customers.”

The Energy Ministry did not directly address detailed questions from The Narwhal about the changes. An emailed, unattributed statement from the ministry confirmed “those costs do not apply to new large projects in specific industrial sectors connecting to the BC Hydro system in the North Coast region” under a new contract created by Dix’s order.

The implications of that change are concerning to Hira.

“The fact that they’re doing this behind closed doors, without any public discussion — that they’re passing on potentially huge costs to taxpayers and not providing any justification — is really alarming,” he said. 

The Narwhal asked both the Energy Ministry and BC Hydro how any additional generation or transmission costs would be recouped and whether the government has estimated how much those costs could be for North Coast transmission line customers. 

In its statement, the energy ministry confirmed those costs “will be recovered from all BC Hydro ratepayers, including those industrial customers.”

The statement did not include any mention of a cost estimate but did note that large industrial customers connected to the North Coast transmission line will pay BC Hydro for the electricity they use, as all BC Hydro customers do. North Coast transmission line customers will also have to pay a security deposit to BC Hydro and cover the cost of power lines to their connection point.

The B.C. government has considered making changes to tariff supplement 6 since at least 2024. A briefing note prepared for Eby in March 2024 outlined the potential for an unprecedented increase in industrial electricity demand, driven mainly by large industrial customers. Requiring LNG, mining and other companies to pay the costs required under tariff supplement 6 “could be prohibitive,” the document stated.

But companies that expect to reap huge profits from B.C.’s natural resources are well positioned to pay their own costs, Hira argued.“The government can’t state that companies that are prepared to invest millions in an LNG pipeline and port facilities can’t afford to pay an electricity connection fee — it simply doesn’t make sense,” he said.

Costs for connecting North Coast transmission line customers could be significant

In addition to Ksi Lisims, the North Coast transmission line could serve “half a dozen private mining projects worth $50 billion in investment,” according to Mining and Critical Minerals Minister Jagrup Brar. 

Under the new contracts in Dix’s December order, none will be required to pay the extra generation and transmission costs required under tariff supplement 6. The Energy Ministry did not respond when asked how much the change could save eligible projects.

However, another LNG project on the north coast provides a hint. Cedar LNG, near Kitimat, B.C., was subject to tariff supplement 6, seemingly for the first time in the transmission contract’s 30-year history. 

To get Cedar LNG connected to the power grid, the provincial government opted to contribute $200 million to help build a new 287-kilovolt transmission line and other electrical infrastructure in July 2025. The floating liquefaction and export terminal could produce three million tonnes of LNG per year for export to Asian markets, using 214 megawatts of electricity.Neither the province nor Cedar LNG replied to questions about how much the company may have contributed toward the transmission infrastructure.If all of the anticipated North Coast transmission line projects come with similar transmission costs, the cost to BC Hydro could be substantial, even before considering the cost of any new electricity-generating capacity that might be needed to meet the new power demand.If electricity prices in B.C. do increase significantly, Hira pointed out B.C. could miss out on attracting other industries to invest in the province. Instead, he said, the province seems to be doubling down on natural resource extraction.

“You’re mortgaging the possibility of diversifying the province’s economy.”

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It’s not exactly a message you want to receive in the middle of a cold winter night. “Extreme cold resulting in high power demand has placed the Alberta grid at a high risk of rotating power outages.” Such emergency grid alerts come with instructions: Don’t charge your electric vehicle. Turn off your lights. Please don’t turn on your oven.

As Albertans’ electricity use sets record after record in recent years, grid alerts are part of the reality. But the reason for them is far from simple — and cold weather alone is seldom enough to send the grid into a tailspin. 

Just last week, the Alberta Electric System Operator published an update to its grid alert system. “Alberta is well prepared to meet the higher electricity demand typically experienced during the winter months,” it said in a press release. “Given current supply forecasts and intertie availability, the risk of resource adequacy issues heading into winter remains very low.”

But it’s not zero.

Here’s what you need to know about grid alerts and how the frequency of electricity shortages could change in the future.

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Quick little recap on what a grid is, please?

Alberta’s electricity grid is complicated, to say the least. 

The grid is a tangle of private electricity generators connecting to private transmission lines, fed into homes by another set of private distributors, plus those bills that would make an astrophysicist’s head spin, all overseen by an arm’s-length provincial operator, provincial regulator and market watchdog (not to mention a very involved provincial government). 

All this to make sure your lights stay on and your smart fridge can recap the latest season of Love Island while nagging you to restock free-range eggs.

But the grid can get dicey, especially with increasing demand. And the Alberta government has recently introduced significant changes to the way the grid is run that bring significant uncertainty. 

So when it all gets to be too much, a grid alert is issued and Albertans are asked to immediately reduce electricity use — for fear if they don’t, the province will not have enough to go around.

So, what’s a grid alert exactly?

Let’s keep it simple to start. A grid alert happens when demand starts to get so high that it might outstrip supply. 

Too many people using power, not enough power being generated.The Alberta Electric System Operator, which manages the grid and tries to ensure enough power flows to consumers, recently changed its alert system. Now the public will only be notified if there is an emergency and there could be rolling blackouts. Previously, it would also advise the public to reduce consumption before an emergency occurred.

If things get really bad, the operator will initiate rolling blackouts, cutting power to different regions of the province. 

The grid operator recently announced new ways of reporting on grid conditions to make it easier to understand, including the severity of alerts. 

Renewable power is the problem, isn’t it?

No, it’s not. 

There’s no doubt renewables add more complexity to the system, contributing power based on variables like wind and sun that run on their own schedule, rather than the exact time electricity is needed. But data from the grid operator showing alerts between 2006 and 2024 doesn’t support the idea that the surge of renewables that started around 2020 made things so unpredictable that grid alerts are happening more often. 

The phaseout of coal power doesn’t have a huge effect, either. 

The first year of data published by the grid operator, 2006, had the most alerts, while 2013 had the most hours of alerts in a given year. Although the operator has not posted summaries of alerts since late 2024, monthly event logs show only one alert in 2025. 

Alerts that were headline news in 2024 — and blamed on renewables by Alberta Premier Danielle Smith — turned out to largely be the result of unplanned outages at natural gas facilities. 

Between 2006 and 2024, renewable generation climbed from less than five per cent of the power supply, to approximately 22 per cent in 2025. 

What causes grid alerts, exactly?

The basic answer is weather and how we respond to it. 

The biggest spikes in alerts over the years have been in July, presumably when things get real hot and everyone turns on fans and air conditioners. September is the second-most popular month for alerts followed by the deep winter month of January.

The operator, in response to questions from The Narwhal, said the September spikes were mostly due to higher-than-normal temperatures combined with planned maintenance that reduced supply.

But, of course, there’s nuance. 

Those large natural gas plants being shut down, for example. Or there could be a catastrophic combination of factors — the wind stops blowing unexpectedly at the same time that some major gas generators are down for maintenance, just as demand ramps up due to weather. 

There is also increasing pressure on the grid as more and more aspects of contemporary life are digitized and electrified. 

If someone points the finger at just one source as the problem during a grid alert — i.e. renewables — it’s usually safe to say that’s an indication that there’s a political narrative at play, rather than a hard examination of the facts. 

Can we expect more grid alerts in the future?

Probably. 

Firstly, there’s the increased demand through electrification of, well, everything. But there’s also increasing uncertainty in Alberta’s electricity market, with the government and the grid operator undertaking a massive restructuring that’s not expected to be fully operational until 2030. That means investors are holding off on expensive decisions until there’s more certainty. 

The recent pipeline agreement between Ottawa and Alberta also includes changes to the electricity grid in the province, with calls to drastically increase power sharing between B.C., Alberta and Saskatchewan and, potentially, nuclear power. 

All of those could have a big impact on the way the grid operates, but details still need to be hammered out. 

And, of course, there’s the lingering effects of the government’s seven-month moratorium on renewable energy projects, the stiffer regulations that followed and the impacts of new rules under the restructured energy market that adversely impact new and existing wind and solar projects. 

There’s also the push for data centres, but so far the Alberta government has restricted their proliferation, realizing there’s not enough power to supply them. Those who want to build new centres will have to provide their own power — a move the government also hopes will use onsite natural gas (reminder: natural gas is largely methane, a potent source of atmosphere-heating emissions). 

While there has been significant additions to power generation in Alberta recently, if investment stalls for several years it could result in not enough power at a time when demand is increasing. 

And that’s a perfect recipe for grid alerts.

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