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.

It’s the summer of data centre controversies in Ontario.

In a season where city council chambers are usually quiet, residents of Hamilton, Oakville, Mississauga, Burlington and Toronto have shown up to public meetings in droves. Many are there to resist proposals for massive new data centres in their backyards, worried about noise, water use and energy bills.

By mid-August, Oakville and Mississauga moved to freeze new data centre construction for a year. Hamilton came within an inch of doing the same.

On Aug. 13, Ontario Premier Doug Ford weighed in. 

Standing in front of a wall of servers at a government-owned data centre in Guelph, Ford unveiled the province’s new “data centre playbook” — and made clear he had little patience for local revolt against the boom he wants to usher in. 

“This is the way of the future,” he said. “Either we do it or Donald Trump’s going to do it, and I’m not giving Donald Trump nothing, absolutely nothing.”

Pushback is also happening in Fergus, Sault Ste. Marie and Armour Township, where a project was cancelled in June in the face of public opposition. Ford calls data centre skeptics “hypocritical,” suggesting residents fighting these projects were “misinformed.”“It just doesn’t add up,” he said, arguing that people can’t rely on artificial intelligence (AI) and cloud storage while also refusing the infrastructure that enables them. 

It was a blunt, campaign-style pitch for a $122-billion industry that has been lobbying hard to take root in Ontario, attracted by its clean electricity grid, temperate weather and proximity to the Great Lakes (four of the five count shorelines in the province). But the data centre push has sparked real concerns about the very few rules governing these massive facilities, and the resources needed to run them.

It’s a story with chapters being written across Canada — including Alberta, where more than 40 are proposed, and New Brunswick, stirring worries about the impacts on old-growth forests and wetlands. Around the world, communities are making it clear they view the centres and the technologies they enable with increasing caution.

And now Ontario is making moves. The province’s playbook has been posted online for public consultation until Sept. 12. It’s currently just a draft, not yet in force — and the legislature won’t be back to debate it until Oct. 27, after an extended summer break.

Here’s everything you need to know.

What are data centres — and why do they matter so much right now?

Strip away the technical jargon and a data centre is just a warehouse full of computers — racks and racks of servers that store and crunch the data behind everything from your email to chatbots to this very story. 

Whether you like them or not, data centres have become the backbone of the modern economy: cloud storage, artificial intelligence, banking systems, health care and government services all run on them. 

They’re not new — Ontario already has dozens — but artificial intelligence has supercharged their scale and size. Today’s data centres are requesting hundreds of megawatts of power, dwarfing older facilities that ran on less power and used less water to cool their servers. While artificial intelligence has its own tension points (which we won’t get into here, but feel free to check out our AI policy), resource use is the root cause of local concerns around the physical space occupied by data centres.

How does a data centre get built in Ontario?

Energy Minister Stephen Lecce has said the province “welcome[s] data centre entrants” — but that welcome comes with strings attached and an approval process that can take up to three years, maybe more. 

The groundwork for this process was laid out first in Bill 40, formally the Protect Ontario by Securing Affordable Energy for Generations Act — the first law governing data centres among provinces — and further in the new playbook.Between the two, it’s clear that data centres need to prove two things to be able to connect to Ontario’s grid.The first is to prove they will be able to cover the full cost of their own electricity connections and use — something other businesses aren’t required to do — so regular households aren’t stuck covering the cost. To enforce that, Ontario wants to create a new, higher electricity rate for any data centre over one megawatt. Quebec’s version of this rate kicks in at five megawatts, so Ontario’s lower bar would catch a lot more projects.

The second is to show the centre will be good for Ontario’s economy. The playbook lays out a three-part criteria to determine this: what jobs, investments and tax revenue it could bring to Ontario; whether it would keep local data in the province; and whether benefits to the host community outweigh the financial and environmental costs. If a data centre can’t satisfy these criteria, Bill 40 gives the energy minister the power to reject its grid connection request. 

“The bottom line is, if a data centre wants to come to Ontario, it is not your right,” Lecce said in a July press conference as the criteria were unveiled. “We now have the right to say no.”

Data centres also have to get approval from municipalities, which determine zoning and building permits. However, most Ontario municipalities don’t yet have zoning rules that specifically address data centres. This means projects can often move ahead on land already zoned for general industrial use, leaving councils with limited power to say no. 

Notably, data centres in Ontario do not have to go through a full environmental assessment, according to analysis from law firm McCarthy Tétrault. It’s also unclear if the province will enforce the constitutional duty to consult Indigenous communities on proposed data centre projects. 

But the province is ensuring other things. The playbook says the government will favour centres that use quieter equipment. It’s also encouraging companies to build their own power supply instead of relying entirely on the public grid, since that can get them running faster than waiting in line for a grid connection. Doing so would exempt a data centre from the process outlined in the playbook. It may also see data centre projects proposed with on-site natural gas plants, as we’re seeing in Alberta. 

One thing neither the playbook nor Bill 40 makes clear is what size of data centre the new process applies to.

How will data centres impact Ontario’s electricity demand?

Significantly — and the numbers keep increasing with every new forecast. 

In 2024, the system operator forecast Ontario’s overall electricity demand will grow 75 per cent by 2050 — a sharper jump than previously projected, driven largely by factories and data centres. The centres are expected to account for about 13 per cent of that new demand by 2035.

A more recent forecast suggested data centres could eventually make up close to nine per cent of all electricity used in Ontario by 2050.

What are data centres using all that electricity for? To stay running all the time; servers never sleep, constantly processing web traffic and requests. 

The province says it’s already fielding interest in data centre builds that would add up to roughly 30 per cent of Ontario’s current peak electricity demand. 

That’s a lot of energy demand — and brings us to the supply challenge ahead.

Will this increase in data centre energy demand result in Ontario using more natural gas?

Possibly, at least in the short-term future.Most of Ontario’s electricity comes from low-emissions sources like nuclear and hydro power. But when demand spikes, like during a heat wave when those who have air conditioners turn them on, natural gas plants are usually what fills the gap, since they can be switched on and off quickly.

That matters for data centres, which run around the clock. If a facility is drawing heavily during one of those peak moments, it could be leaning on gas power to do it. And that fossil fuel is primarily made up of methane, a potent greenhouse gas driving climate change and the worsened wildfire seasons, floods and other severe weather we’ve experienced as a result.

How will data centres impact Ontario’s water usage?

We don’t know yet. 

Existing large data centres use water-based cooling systems to keep servers from overheating. That means that all the water pulled into a centre absorbs the heat from the servers and evaporates into the air. Any water that doesn’t evaporate is reused and then sent to a local plant as wastewater. In closed-loop systems, water just circulates in pipes that cool the servers, so there is little lost to the air. 

According to one estimate, a single one-megawatt data centre can use up to 25.5 million litres of water a year just for cooling — about what all of the homes in the city of Mississauga use in a day. Many of the data centres being proposed in Ontario are larger than that, which means, depending on their cooling system, they could also be using a lot more water. 

Microsoft is building three data centres in Ontario, which share an estimated total demand of approximately 200 megawatts. One planned in Toronto’s Etobicoke area was approved to use up to about 40 litres of water every second for cooling — that’s about five bathtubs full every five seconds, and 1.2 billion litres a year. A separate Microsoft complex in Vaughan is expected to use about 730 million litres of municipal water a year.

The province’s playbook says Ontario will favour data centres that use water-free or closed-loop cooling and reuse waste heat — for instance, to help warm nearby buildings.

What are Ontario municipalities doing about data centres?

On Aug. 11, Oakville became the first Ontario municipality to pass a one-year pause on building new data centres. Mississauga is set to follow suit. Both were facing major AI data centre proposals, or at least land acquisitions that suggested them.

Other municipalities are taking different approaches. Hamilton voted down a proposed pause. Burlington and Waterloo Region have asked staff to review existing rules and impacts. Both, along with Toronto, have asked the province for clearer regulations. Centre Wellington and Sault Ste. Marie are sussing whether they can pass temporary bans.

Ford has resisted calls for a province-wide ban, saying local councils will still have a say and that he’d “rather go to a willing host.” While Ontario law requires municipalities to indicate their support before a wind or solar farm can be developed (usually through a council motion or resolution), no such formal rule was proposed in the data centre playbook.

What does Doug Ford mean when he says Ontario needs data centres to address ‘data sovereignty’?

Both Ford and various companies aspiring to build data centres in Ontario have framed this push as a matter of national security: keep the servers here or risk losing control of Canadians’ data to countries like the United States. 

But it’s harder said than done. Yes, building data centres would mean Ontarians’ data is kept in Ontario physically. But what actually determines control over data isn’t the building’s location — it’s who owns the company running it, and which country’s courts and laws they’re accountable to.

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On Aug. 6, with much of southern B.C. blanketed in wildfire smoke, Minister of Energy and Climate Solutions Adrian Dix kicked off a Campbell River press conference by thanking wildfire fighters and the BC Hydro employees working to address infrastructure damaged by the flames.

“The impact of climate change and the impact of wildfires presents challenges to BC Hydro,” Dix acknowledged, adding wildfires had knocked out power for about 24,000 B.C. homes over the previous week.

A few days prior to the minister’s announcement, wildfires near the central B.C. communities of Clinton and Vernon had destroyed hundreds of homes and prompted evacuation orders affecting about 8,000 people.

But Dix wasn’t on Vancouver Island to talk about the wildfires. He was there to announce the purchase of Island Generation, a 275-megawatt natural gas-fired power plant, by BC Hydro. Despite a mandate that all electricity generated in B.C. come from renewable sources by 2030, BC Hydro now says it needs to continue getting electricity from gas to meet an anticipated surge in power demand over the next few years: a 20 per cent increase by 2030 and a 50 per cent increase by 2050.

That surge in demand is driven largely by mining and liquefied natural gas (LNG) projects, as well as increasing numbers of electric vehicles and heat pumps in B.C. homes.

Keeping gas in BC Hydro’s generation mix will allow the provincial power utility to focus on developing more renewable energy sources, Dix argued.

“It’s better to continue to build out clean electricity and to ensure that resources like Island Generation stay in B.C. and support the system,” he said, calling climate action “essential” to B.C.’s environmental, economic, social and cultural well-being.“Surely things like our own wildfires, and then witnessing what’s happened, for example, in France, in Spain, in other parts of the world, demonstrate this,” he said.

The day after the Campbell River announcement, the Bald Ridge fire ignited near Summerland in southern B.C., leading to the evacuation of more than 20,000 people. On Aug. 8, Premier David Eby declared a provincial state of emergency due to the wildfires. B.C. is now in its third state of emergency in five years, including those prompted by the November 2021 atmospheric river and the extreme wildfires of 2023.

“Climate scientists have connected the dots to all three of those emergencies and been able to identify that climate change made them both more likely and more extreme,” Dan Woynillowicz, a climate policy expert and principal with Polaris Strategy + Insight, said after watching Eby declare a state of emergency. “And neither the premier nor either of his ministers made even passing reference to climate change in that whole press conference.”

Some might say that connecting the “explosive and extremely dangerous” conditions driving this year’s wildfires to climate change is in poor taste while people are being displaced and losing their homes, but Woynillowicz takes a different view. 

“I think British Columbians are sophisticated enough to be able to hear those different messages,” he said. “What we need to continue to do to better prepare and adapt to a world in which we are going to be experiencing this with greater frequency and greater extremity, but also what we need to do to prevent even worse impacts in the future by reducing our combustion of fossil fuels that are that are creating the problem and making it worse.”

Failure to plan for future electricity demand makes Island Generation purchase an ‘unfortunate necessity’

Gas isn’t a big part of BC Hydro’s electricity generation, about 2.5 per cent. The emissions reduction from BC Hydro ditching gas would not be huge, and there are arguments for keeping facilities like Island Generation online as energy demands grow across B.C.Island Generation is what’s known as a peaker plant, mostly called on to generate power at times of peak demand like hot summer days and cold winter nights. Over the past five years, it’s been running for about five days per year and BC Hydro expects that will continue. 

The plant can create enough electricity to power about 125,000 homes — about one-quarter of all the electricity that can be produced on Vancouver Island, making it an important local asset.Evan Pivnick, associate director of public affairs for Clean Energy Canada, called the Island Generation purchase an unfortunate necessity — one that shows BC Hydro’s planning has not kept pace with the growing electricity demand it faces.

“This needs to be an opportunity to learn from those mistakes, so that we truly look at natural gas as an option of last resort, not as something that plays a growing role in our electricity systems,” he said. 

B.C. is set to achieve just half of its legislated target of reducing emissions by 40 per cent below 2007 levels by 2030, according to the most recent climate accountability report. 

“Rather than closing the gap to the 2030 target year after year, we’ve been getting further away from it,” Kathryn Harrison, a political science professor at the University of British Columbia who studies climate and energy policy, told The Narwhal.

“Since that report was published [in 2025], the B.C. government has weakened some climate policies and, as far as I can tell, abandoned others,” she added, citing B.C.’s discarded pledges to develop an oil and gas emissions cap and reduce medium- and heavy- truck emissions, as well as the elimination of the consumer carbon tax.

Electrification — replacing fossil fuel power sources with electricity — is central to almost all of B.C.’s emissions reduction goals. But as B.C. fast-tracks energy-intensive resource projects, BC Hydro has yet to figure out how and when it would have those resources ready to supply them with power. 

“There was no accompanying electricity strategy,” Pivnick said. “There was a disconnect where the ambitions around electrifying industry, electrifying households, never translated into what does this mean for our electricity system and how do we think about the buildout of the supply that’s required?”

Even the 50 per cent increase in electricity demand by 2030 that BC Hydro is currently working to meet is likely a conservative estimate. Woynillowicz noted the federal government’s electricity strategy projects a doubling in electricity demand across Canada by 2030.

“BC Hydro has continued planning for, relatively speaking, a lower-growth future, and I think that is now coming back to bite,” Woynillowicz said.He wondered whether a more proactive planning approach could have allowed BC Hydro to develop renewable resources and avoid continuing to rely on Island Generation. Despite launching the CleanBC program in 2018 and investing $3.5 billion in its efforts to cut greenhouse gases, B.C. has not been successful at reducing emissions in the province and has admitted the program’s goals are no longer “accurate or workable.”   

“Hindsight is 20/20, but I think it raises questions,” he said. “Between BC Hydro and the government, was planning happening in the way that it needed to be? I would say that no, it wasn’t. That there was fundamentally a disconnect between CleanBC and the future that BC Hydro was planning for.”

LNG ambitions could lead to electricity crunch and higher gas prices

The pressing need for power that B.C. faces is relatively new. Before the NDP government committed to completing the Site C dam, some experts estimated the province would not need the 1,100 megawatts the dam can produce for a decade or more after it began operating. There were also those who argued renewable power sources would be a better bang for the B.C. government’s buck.

But just electrifying all proposed LNG terminals in B.C. — something the government has made a condition for those projects to proceed — and some of the gas infrastructure to supply them would take 40,000 gigawatts per year. That’s 7.5 times the capacity of Site C, as noted in the CleanBC review co-authored by Woynillowicz and fellow climate expert Merran Smith.

Electrification is key to the main marketing slogan for B.C.’s LNG, as Premier Eby emphasized during a recent press conference.

“Our LNG is the lowest carbon in the world because it is electrified as much as possible throughout the chain [and] because we have high standards around methane leakage and emissions,” he said. 

“We take climate change very seriously, but we also recognize that B.C. can play a role in driving down carbon pollution around the world.”

But the massive electricity demand for LNG could put B.C.’s electrification and emission reduction goals in peril.

“If we don’t have enough electricity to power LNG and potentially also electric vehicles and home electrification and other industries, we will end up either not pursuing those projects or increasing our emissions,” Harrison said. 

She also pointed out that B.C.’s most recent emission projections don’t include some of the LNG projects the provincial government has been pushing hard to see built: LNG Canada Phase 2 and Ksi Lisims. If those facilities fire up, it will add “many millions of tonnes difference” to how realistic the province’s emissions reduction goals are.

The economic opportunities offered by becoming a global LNG supplier are real, Pivnick said, but they may not outweigh the downsides.

“The world would be very happy to see Canada and B.C. invest in more and more fossil fuel projects that ensure there’s a secure supplier available to purchase from as they go through their own transitions, but that’s Canada and B.C. choosing to invest as essentially a shock absorber for a world that’s trying to move away from our goods,” he said.

A robust LNG industry will also mean much higher demand for natural gas in B.C. The province’s 2026 budget banks on a doubling of natural gas prices. That could be bad news for affordability in B.C. down the road, given natural gas accounts for about 31 per cent of all energy used in the province, while electricity accounts for about 18 per cent.

“Whether we’re talking about burning natural gas in our homes or burning natural gas for electricity, continuing to have that reliance at the same time that we’re actively trying to secure higher prices, [that is] good for the oil and gas sector, good for the province in terms of royalties, but it’s actually pretty lousy for British Columbians from an affordability perspective,” Woynillowicz said.

Back in April, Dix told the legislature Island Generation had been having trouble with its gas supply, an issue he attributed to demand from the Woodfibre LNG project in Squamish. In July, The Narwhal’s questions to the Energy Ministry, Island Generation and Woodfibre LNG about the supposed supply issue mostly went unanswered.

At the Aug. 6 announcement, Dix said he is confident Island Generation will be able to get the gas it needs, but offered no further information.

Concern for climate change has spiked as wildfire smoke spreads, creating an opportunity for conversation

A very dim silver lining to the summer’s wildfires is that they seem to have put climate change back on many Canadians’ radar. A recent Angus Reid poll found 21 per cent of Canadians put climate change as their top concern, up from 14 per cent in March. In B.C., 25 per cent of respondents said climate change was their top concern, putting the issue in third place behind cost of living and healthcare.

That’s a notable shift from the past few years, when climate change has consistently polled low as a priority for many Canadians. But just because people aren’t telling pollsters climate change is a top concern doesn’t mean they aren’t worried about the impacts of a warming world, Harrison argued.

“I don’t think it is the case that that means people are willing to sacrifice their safety from wildfires, their children’s health from breathing smoke, their elderly parents’ safety in extreme heat in exchange for a lower cost of living today,” she said. “They’re just not connecting those dots.”

That lack of connection isn’t helped, she said, by politicians who claim they take climate change seriously while continuing to support fossil fuel development and failing to address emissions effectively.

“Politicians are reassuring people, ‘Don’t worry, we’ve got the whole climate change thing in hand,’ and people at the same time are worried about the economy,” she said.

Instead of offering reassurances that things will be okay, Woynillowicz wishes politicians would communicate what they are doing to directly and effectively address climate change.

“One of the messages we’re hearing from government is that they’ve got our backs,” he said. 

“I would feel more comfortable that they’ve got my back and my kids’ backs if I knew that … they are actually being proactive, both in terms of helping make us more resilient to future impacts that we know are coming — but also what they’re doing to prevent even worse impacts in the future by doing more to reduce the pollution that’s causing the problem.”

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Summary

• The Manitoba Métis Federation and U.K.-based Renewable Energy Systems are proposing a 200-megawatt wind farm in rural Manitoba as part of a provincial push to install 600 megawatts of majority Indigenous-owned wind power by 2035.
• Residents of Polonia, Man., are opposed to the plan. They worry it would be a blight on the beautiful landscape, cause negative health impacts and saddle the local community with new expenses.
• Manitoba lags behind other provinces when it comes to wind power capacity, and the provincial utility says new wind projects could help to address a looming electricity shortfall and make progress toward net-zero targets.

Leonard Kaspick can list just about every household in Polonia, Man. 

“There’s someone living right across the northeast, someone living behind here, about a quarter mile there’s a house there, then a half mile there’s another house there, I’m here, and then on top of the hill there’s someone else there,” he says, standing in the heartbeat of the hamlet: a community hall just off the main road. 

Besides the hall and the smattering of homes, there’s a historic (though out-of-commission) church next door and a single general store further down the road. 

“There’s less people here now than there was in 1885,” 83-year-old Kaspick jokes as he wraps up a condensed history of the Western Manitoba community. 

“The people that come here like the solitude and the beauty of the area.”

Polonia itself isn’t in the census, but together with the five nearby towns that make up the Rural Municipality of Rosedale, the population is listed at just over 1,500. Situated 13 kilometres beyond the southern tip of Riding Mountain National Park and more than 200 kilometres west of Winnipeg, it sits along the edge of the Manitoba Escarpment, a steep ridgeline carved out by the glacial Lake Agassiz thousands of years ago.

It is not a typical Prairie landscape. Instead of open patchwork fields stretching flat across the horizon, the valley is all rolling hills, dotted with cattle farms, crop lands, wetlands and forests. The ecology is unique; microclimates and fertile soils allow for rare and diverse species of plants and animals.

It’s unique in another way too: thanks in part to the ridgeline, this pocket of the province boasts some of the strongest winds in southern Manitoba, according to federal wind atlas data. And with its proximity to the Manitoba Hydro substation in Neepawa, it’s an ideal place for wind turbines.

In April, the Manitoba Métis Federation and U.K.-based Renewable Energy Systems announced a joint proposal to build a 200-megawatt wind farm in the area. 

The Fleury Winds project, majority owned by the Métis Federation, would consist of about 30 turbines, each more than 700 feet tall, situated on private farmland in and around Polonia.

The pitch is part of a provincial initiative to install 600 megawatts of majority Indigenous-owned wind power by 2035 to both address a looming electricity shortfall and progress toward net-zero targets.

“When we think about these projects and the meaningfulness for us, it’s as much about provision of energy for the province and the opportunity to participate economically as it is … a source of pride to be part of a project of this size and scope for our people,” Lorne Pelletier, senior economic advisor to Manitoba Métis Federation president David Chartrand, says in an interview.

Fleury Winds is the first energy infrastructure project to be undertaken by the Red River Métis Power Corporation, a newly created arm of the Métis Federation.

But many in Polonia aren’t sold on the project.

Some object to wind turbines disrupting the region’s beauty and tranquility, Kaspick says. Others worry the turbines could cause negative health effects, disturb wildlife habitat and migratory birds or strain the municipality’s infrastructure. 

“I looked at the map and where my house is located, straight out my picture window, I will see a roughly 705-foot-tall wind tower,” Polonia resident Trevor Bennett says. “And they say I will not only see it, I potentially will hear it all the time and will potentially even feel it.” 

While the Métis Federation and the energy company have been putting the final touches on a proposal that will be presented to Manitoba Hydro in July, some Rosedale residents, including Bennett, have formed a citizen group that’s working to elevate community concerns and preserve their “piece of heaven.”

Fleury Winds turbines would tower over every other structure in the region

Bennett works in the agricultural equipment industry and has a young family. After about 15 years working in nearby Neepawa, he moved his family to Polonia a little over a year ago for “the peace and quiet and tranquility,” he says. 

“I moved here because there wasn’t stuff like that [the wind farm] here.” 

Several months ago, he started hearing “rumblings” his countryside oasis was being considered as the site for a major wind-power development. 

He later learned the project proponents were meeting with landowners to secure lease agreements that would allow wind towers to be built on their land in exchange for financial compensation. 

In April, some landowners who have signed agreements with the Fleury Winds project told the Brandon Sun the opposition may not reflect the feelings of all community members. Pelletier says the project has “a strong base of landowner support.”

But according to James Mitchell, another Polonia-based member of Piece of Heaven, the citizen group opposing the Fleury Winds project, those early whispers created a sense of secrecy around the development. The first time Mitchell and Bennett heard any concrete details was during an open house at the community hall in April. 

“It went from ‘that’s just a rumour’ to a reality for me,” Bennett says.

The town hall was structured as a drop-in information session. Representatives from the Métis Federation and Renewable Energy Systems were stationed around the room with poster boards outlining the basic details of the proposal.

The project would consist of between 28 and 36 wind turbines, situated on private farmlands between the towns of Neepawa, Minnedosa, Birnie and Hilltop. A project map highlighted the 40-odd properties that had already signed agreements, the locations of nearby houses and the proposed turbine sites.

Each of these “modern” turbines would be up to 210 metres (705 feet) tall, including the length of the blades, and built atop concrete foundations more than 20 metres wide and buried four metres deep. 

They would generate between six and eight megawatts each for a total project capacity of 200 megawatts — enough to power 59,000 homes — in ideal circumstances. This energy would be linked to the Manitoba Hydro grid via buried cables connected to an existing substation in Neepawa. 

“It’s an incredible way of generating energy and electricity for Manitobans,” Pelletier, who attended the open house, says. 

“It means a lot to our people: the job creation that it entails, the opportunity that it presents for us to be … contributors in the economy, and the benefits that it will bring not just for Red River Métis but all Manitobans.”

But some Polonia residents, including Mitchell and Bennett, believe the company should have done more to build trust in the community in advance. Now that the proposal is in motion, it feels like it can’t be stopped, Bennett says.

“I think they were trying to label it as a consultation. I really don’t feel that was a consultation at all,” Bennett says.

As a father, Bennett worries how living so close to a tower might affect the well-being of his children.

As wind turbines have become more common worldwide, several jurisdictions have reported receiving complaints of hearing issues, heart palpitations, vertigo, poor sleep, migraines and other noise-related health impacts from people living in close proximity to the towers. The majority of peer-reviewed research has found no direct correlation between these symptoms and turbine noise. Many studies do, however, acknowledge turbines can cause “annoyance.”     

Other residents in Polonia worry about the impacts of shadow flicker — a term for the intermittent shadows created by spinning turbine blades. And they are concerned for the birds, bats and other wildlife that criss-cross the region’s fields and could be driven away — or killed — by the turbines.

The area is, as Mitchell describes it, “strictly rural.” The largest industrial developments are a handful of gravel quarries. Off the main highway, the roads are all gravel; some are hardly more than twin tire tracks scything through the rugged hills. The tallest structure around is a spindly 250-foot-tall cell tower. 

“Imagine something two-and-a-half times as high on a base that’s 100 feet in diameter. It’s not just a little pole up in the air, it’s a massive, massive structure,” Mitchell says. 

To put it in perspective, the tallest building in downtown Winnipeg — 300 Main St. — is about 465 feet tall. The turbines at Manitoba’s existing wind farms are about 120 metres, or 400 feet. The proposed Fleury Winds turbines would dwarf them both.

Mitchell worries the equipment needed to build these behemoth towers — cement and gravel trucks, massive trailers hauling 90-metre-long turbine blades — will cause costly damage to the town’s roads.

When the towers reach the end of their life 30 years down the line, Bennett and Mitchell worry Polonia will be left to clean up the aging infrastructure while the company takes its money elsewhere. 

“My big concern is that the proposed economic benefits to individuals and the [rural municipality] … is not even going to come close to outweighing the drawbacks,” Mitchell says.

Manitoba Métis Federation surprised at pushback, while opponents say consultation was lacking

With these and many other questions in mind, a group of residents took to the hall’s stage partway through the April open house, turning what was conceived as a smattering of one-on-one conversations into a community-led question-and-answer period. While Mitchell believes the company’s representatives were trying their best, the information they offered was broad, and many of the questions remained unanswered.

At the Manitoba Métis Federation, Pelletier says the meeting’s spontaneous turn came as a surprise. While he understands that some community members felt the open house lacked transparency, the project group thought it would be more respectful to speak directly with residents and answer questions as they arose, he explains.

“We went there with the intent to talk about the project, present the project, but really to engage one-on-one with the community,” he says. 

The project is still in early stages; the open house is just the beginning of the planned consultation. While figuring out the timing of engagement sessions like the open house can be “tricky,” the Métis Federation takes the community’s concerns seriously, he adds. If the project is selected, the organizations expect to undergo two years of licensing and permitting before construction would begin in 2029.  

“The project is proposed within our homeland as Indigenous people, and we have a long-standing and very strong commitment on the part of our government for environmental stewardship,” Pelletier says.

Renewable Energy Systems Canada’s director of development, Isabelle Deguise, said in a statement: “There will be real opportunity in the months and years ahead to sit down with people in the Polonia area again, hear what matters to them and shape this project together.” 

“We know residents have questions, and we want to listen. Our commitment is to keep turning up, keep listening and keep working with this community throughout the life of the project.”

Manitoba and federal governments see wind farms as the future of power

Wind power developments are not new in Manitoba. The St. Leon and St. Joseph wind farms, built in 2006 and 2011 respectively, are located about 100 kilometres south of Winnipeg and together produce about four per cent of the provincial power supply.

St. Leon has about 70 turbines; St. Joseph has 60. Each produces approximately two megawatts and their towers, including the blades, stand roughly 120 metres tall.

Pattern Energy, which operates the St. Joseph farm, estimates that over the project’s first 27-year power sale contract, it will pay $44 million in property taxes and generate $38 million in revenues for landowners.  

At the time it was built, St. Joseph was one of the largest wind farms in Canada, according to then-premier Greg Selinger. 

“This project builds on Manitoba’s position as a leader in renewable energy development, complementing our existing hydroelectricity supply, geothermal activities, biofuel production and aggressive energy-conservation programming,” Selinger said in a news release the day the turbines started spinning.

But momentum for wind power developments petered out after St. Joseph was built. As of 2025, Manitoba has installed fewer than 260 megawatts of wind power, while neighbouring Saskatchewan has more than 800 megawatts, Quebec has more than 4,000 megawatts and Ontario and Alberta have more than 5,500 megawatts each. 

Some in the province would like to see Manitoba pick up the pace of wind-power development. According to research from Climate Action Team Manitoba, the technology is well-suited to winter production, with Manitoba’s existing wind farms already generating more energy in fall and winter than summer and the province is no stranger to the kinds of high-wind speeds that make turbines a sensible investment. At the national level, the Canada Energy Regulator projects wind will make up about 70 per cent of renewable energy growth in the coming years. 

Scott Blyth, a retired doctor from nearby Brandon, volunteers with the Manitoba committee of Canadian Association of Physicians for the Environment. Following the open house, he wrote an opinion article criticizing Polonia residents for “hijacking” the meeting. 

Reflecting on that article in an interview last month, Blyth said he could “understand people’s concerns” about the turbine development, but stressed his excitement for renewable energy projects in the province. 

“There’s so much good that can come from this approach to generating energy, and boy, my bottom line is, get rid of fossil fuels … and why haven’t we done this sooner?” he says.

Fleury Winds is part of a provincial initiative that looks to turn the tide on wind power in Manitoba by installing 600 megawatts of majority Indigenous-owned, utility-scale wind farms.

The initiative was first introduced as part of the provincial government’s 2024 affordable energy plan, then re-affirmed in 2025, when Hydro released a roadmap outlining its path to a reliable net-zero energy grid. 

The initiative is intended to help add capacity to the province’s strained energy grid, while providing Indigenous Nations “new opportunities to participate and benefit from the energy transition,” according to the affordable energy plan.

The additional grid capacity is necessary to address a projected shortfall as soon as 2030, the utility noted in 2025. Other measures outlined included efficiency programs to reduce demand, enhancements to the existing hydropower grid, new natural gas-powered combustion turbines (currently slated to be built in Brandon) and the addition of five megawatts of utility-scale battery storage.

While the best-case scenario for wind power in the province is 600-megawatts of production, the reality is that wind — and the power it produces — is intermittent. Manitoba Hydro expects that in reality, the wind power developments will generate 120 megawatts of reliable, accredited capacity.

Hydro issued the official call for proposals in March, with submissions due by early July. 

It received proposals from 11 eligible proponents representing seven Indigenous Nations (including the Métis Federation, Swan Lake, Dakota Tipi, Gambler and Pinaymootang First Nations, Fisher River Cree Nation, and Keeseekoowenin Ojibway First Nation) and six established wind power companies.  

The utility is expected to announce its preferred proponents in spring 2027, with projects complete by 2035.

Polonia isn’t the only community pushing back against the proposed developments. 

A wind farm proposed by Swan Lake First Nation and Innergex Renewable Energy is facing opposition from residents from the Rural Municipality of Lorne, some 150 kilometres southwest of Winnipeg. They worry about negative environmental and economic impacts in the agriculture-dominant region, and would like to see towers built on Crown land, or further north.

Polonia, Man., wind farm wouldn’t come online until 2035

Progress will be slow. The proposed turbines are not expected to come online until 2035, according to Manitoba Hydro. 

In the meantime, proponents whose projects are selected by Hydro will need to complete environmental licensing processes to address a myriad of environmental and community impacts. 

The provincial wind power guidelines require companies to assess the extent of shadow flicker within 1.5 kilometres of each turbine, the impact of noise across the entire development and the potential impacts to wildlife including migratory birds, bats, roosting and foraging habitats and endangered species.

As for human impacts, a 2013 Health Canada study that surveyed about 1,200 Ontario and P.E.I. households in proximity to wind towers found no correlation between negative symptoms such as headaches, tinnitus and dizziness and turbine noise levels. 

The study did, however, find a correlation between turbine noise and community annoyance, with participants highlighting the effects of shadow flicker, vibrations, sound, visual impacts and blinking lights. 

Long-term annoyance was linked to stress indicators such as high blood pressure and cortisol, the study found, particularly for those living closest to the turbines.

As a result, best practices indicate turbines should not be built within close proximity to people’s homes. In Manitoba, turbines may not be within one kilometre of a residence.

Pelletier stresses the well-being of community members and the local environment is paramount for the Métis.

“These are our lands too, right? We’re not just a corporation coming in from afar. We live in the area, we demonstrate a strong commitment to environmental stewardship,” he says.

Turbine technology has evolved, he adds, and many of the community’s concerns can be mitigated by choosing turbines with lower noise specifications, conducting thorough environmental assessments and by taking responsibility for the turbines through their lifetime and decommissioning. 

“For us, it’s not just about meeting the regulatory requirements, it’s pushing beyond that. From an Indigenous perspective, these are things that are integrated in the way we think,” he says.   

The Piece of Heaven group plans to keep making their voices heard. Most recently, they organized a letter-writing campaign delivering a list of concerns to municipal councillors, MLAs and provincial ministers.

Response from Rosedale councillors has been positive, Bennett says. Some have reached out to arrange meetings and hear more about residents’ concerns, while the provincial government sent acknowledgement letters, he adds. 

Bennett could envision a version of the project with smaller towers, larger setbacks and more equity for landowners. He would like to see more stringent regulations on where the turbines are placed, given the existing rules were written for smaller turbines. 

But there are others, like Mitchell, who would rather the project be moved out of the area entirely. In his mind, the rewards will never outweigh the risks.

Julia-Simone Rutgers is a reporter covering environmental issues in Manitoba. Her position is part of a partnership between The Narwhal and the Winnipeg Free Press.

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

• The Alberta government is hoping to attract $100 billion worth of data centres to the province over the next four years. If built, the data centres would require enormous amounts of electricity to operate.
• With a cap on how much electricity data centres can purchase from the provincial grid, most will have to generate their own power by burning natural gas, a fossil fuel.
• A global surge in demand for natural gas plant infrastructure is driving up costs and extending wait-lists, calling into question how realistic Alberta’s data centre ambitions are.

The Alberta government has big ambitions for AI data centres, but those dreams will have to contend with the harsh reality of a heated global competition for electricity. 

Around the world, there is a shortage of turbines used in natural gas power plants, as more and more electricity generation is built to feed hungry data centres. Estimates for wait times to obtain the critical components are now upwards of five years. Prices have also increased dramatically. 

That has serious implications for Alberta’s plan to attract $100 billion worth of data centres over the next four years, not only in terms of how quickly the facilities can be built, but also at what cost. 

As if to drive the point home, the province joined private industry on July 2 for the announcement of the $4.6 billion Greenlight natural gas power plant, which is 2.6 times more expensive than a similar sized power plant completed by the same company two years ago. That plant will feed electricity to a $15 billion Meta data centre.

“We’re definitely seeing the impact of that turbine supply crunch,” Will Noel, senior electricity analyst with the Pembina Institute, says. 

These power plants burn natural gas, a source of the potent greenhouse gas methane, to spin turbines that generate electricity. Natural gas power generation accounts for approximately 77 per cent of Alberta’s electricity grid.

The turbine shortage comes on the heels of the province’s overhaul of its electricity market, a move that has stalled power plant investment as companies wait for more certainty before committing. It also follows the government’s crackdown on renewable power generation, which decimated the market for wind and solar in Alberta.

Data centre developers face lengthy waits and a highly competitive process if they want to connect to Alberta’s grid, but can move quickly if they build their own power supply — which the grid operator requires to be natural gas, at least for now. 

The operator, in response to questions from The Narwhal, said that’s because developers must be able to meet their power demand at all times.

“Renewables and stand-alone storage are currently excluded because of weather dependency and duration limitations,” a spokesperson said by email. “As of now, they are not qualified to reliably offset a data centre’s around-the-clock draw the way dispatchable gas generation can.”

New technologies could change that, according to the operator. 

If the proposed data centres don’t already have their turbines ordered, it’s going to be a long wait. 

Noel says we don’t actually know how many of the 41 data centre centre proposals in Alberta as of July 7 have finalized designs and parts on order. It’s also not known if any will eventually connect to the grid. 

“This is obviously speculation,” he says, “but I imagine most of these data centres don’t have turbines ordered.”

The global turbine shortage

Across the world, but particularly in the U.S., data centres are being built at a furious pace. That, along with a broader turn to electrification and production challenges, is creating a bottleneck for turbines and additional power plant components. 

A report from Bloomberg says the cost of building a natural gas plant in the U.S. increased 66 per cent between 2023 and 2025, while the time it takes to complete construction has increased 23 per cent in the same time period. 

The pressure to build and the lack of components is creating bidding wars on turbines and swelling the bottom lines for turbine manufacturers.

GE Vernova, one of the few large-scale turbine suppliers, saw significant growth last year and into 2026, and has a backlog of orders that account for 100 gigawatts of potential power supply. (For reference, that’s nearly one-third of the electricity the entire city of Calgary uses in a year.) 

All three of the major turbine suppliers are reporting delays.

That supply crunch has led some data centre developers in the U.S. to go to extreme lengths to get power, including repurposing old jet engines. 

Noel calls those fixes “inefficient and very costly,” but notes “the revenue they’re getting from the data centres is outstripping the extra cost, so they’re just kind of doing what they can to get any power on site as fast as possible.”

In Alberta, a power surplus could quickly evaporate

There is nothing to that extent happening in Alberta, which quickly instituted a hard cap on how much power was available to data centres from the existing power grid.

The Alberta government has embraced the AI boom as a way to increase demand for the province’s vast natural gas reserves. 

“Jurisdictions that can provide reliable and affordable power will have a serious advantage in attracting investment, and with our vast natural gas resources and mature industrial infrastructure, that is exactly what Alberta can offer,” Premier Danielle Smith said while announcing the recent Greenlight project.

The Alberta Electric System Operator, which manages the province’s private grid, allocated 1.2 gigawatts of power for data centres in a competitive process that ended with two developers allowed to tie into the grid. 

Another round will dole out additional power and the system operator recently announced data centre developers planning to build their own power plants could temporarily tie into the grid while those plants are being built, up to 1.6 gigawatts. 

The operator said by email that the “bridging provision” is a “general mechanism accommodating a time gap (up to three years) between a load being ready to operate and its generation being fully built and in service for any reason.”It is up to the developer to ensure it has the necessary power after that three-year window and if there is a power shortage during those three years, data centres using the bridging provision would be the first to have electricity curtailed. 

The province also has a healthy cushion of extra power after a buildout of capacity prior to market reforms and a renewable crackdown. But that won’t necessarily last. 

Noel points to the insatiable data centre demand and resulting supply crunch, combined with population growth and increasing electrification as pressures on the system. 

“And then we’ve got the old coal plants that were converted to run on gas — those are coming up soon on their end of life,” he says. “So I think mid-2030, if we don’t kind of deal with this now — whether it’s more gas or more renewables or whatever — I think there’s a real possibility that we will go from flush with power to just scraping by again.”

The office of Alberta’s minister of affordability and utilities, RJ Sigurdson, didn’t reply to specific questions about the turbine shortage and its impacts, but said the government prioritizes the “well-being of Albertans” and “will not compromise the reliability or affordability of the electricity that millions of Albertans, Indigenous communities and our local industries depend on.” 

The minister’s office said the government “does not prescribe a specific generation technology for powering data centre projects.” It said the decision by the grid operator to limit generation to natural gas at this time is an independent decision by the arm’s length body. 

The Alberta Electric System Operator says its role is to ensure the safety and reliability of the grid and it does not track whether private developers have ordered the necessary equipment.

So what does this all mean for Alberta’s AI data centre dream?

The Narwhal reached out to all of the big natural gas generators in the province to see if they were being impacted by turbine delays and cost increases, but received no responses. Emails to two data centre developers, Beacon Data Centers and Synapse, also did not get a response. 

It can be difficult to assess how the various companies could be impacted by the current race for power plant components, but applications to the Alberta Utilities Commission, the regulator for power plants, provide some insight. 

Synapse, which hopes to start construction on a data centre near the town of Olds in October, hasn’t disclosed who will build its turbines, but says once final decisions are in place, it could have them on site within a month. It plans to use modular generators, operating alone, before completing construction of a full system while the project is online.

In the company’s application to Alberta Environment and Parks, Synapse says it will use generators from Alberta-based Eco Power Equipment, which specializes in portable gas generators. Eco Power said it doesn’t manufacture turbines. 

Another data centre moving through the regulatory process is Beacon Data Centers’ Indus project, southwest of Calgary. 

Its application to the regulator shows details on turbine components and has a target of Dec. 31, 2028, for completion of the project, pending approval.

Alberta’s electricity market overhaul stalls investment as companies wait for more certainty

As those projects move through the regulatory process, large electricity generators remain cautious about building new projects to help keep the lights on.

There are also questions about how the data centre boom could impact prices. Premier Smith says the Greenlight project could help bring down transmission costs, which ultimately show up on electricity bills. Noel agrees that’s possible. 

But the flip side is increased demand for natural gas and the trickle down of massive cost increases for building power plants could potentially increase electricity or heating bills. 

“I think everyone’s kind of sitting and waiting to see how the [restructured electricity market] plays out,” Noel says. 

“In 2028 we’ll phase out the old market and bring in the new, and maybe then we’ll start to see investment, but that’s a pretty long time.”

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

• 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.”

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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.

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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.

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 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.

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

• 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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