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

Summary

• Haida Gwaii is one of 44 remote communities in B.C. that are not connected to the provincial electrical grid. For power, most rely on diesel, which has heavy environmental and human health costs. 
• Solar North, a two-megawatt solar project by Haida-owned Tll Yahda, came online in December — the first project of its kind to be built on a remote grid in B.C., and a big step forward in the First Nation’s plans to transition off diesel.
• Whether operating independently or with BC Hydro, remote projects require funding to get off the ground. However, a key federal grant program by Natural Resources Canada to fund diesel reduction will end next year.

On a hot, sunny day in 2023, a flatbed truck sidled up to the flat patch of grass at the Masset airport on Haida Gwaii. Kevin Brown, Patrika McEvoy and Sean Brennan had rushed to the site when they heard the solar panels had arrived. After decades of advocating, planning and waiting, the Haida Nation’s first utility-scale solar energy project — the first of its kind on a remote grid in B.C. — was ready to be built. 

All three remember the moment when Brown, energy coordinator for Old Massett Village Band Council, reached out his finger to touch one. 

“Shit just got real,” he says.

Kevin Brown, energy coordinator for Old Massett Village Band Council, rushed to the airport to see and touch his community’s new solar panels when they were delivered on-site in 2023. The solar panels came online late last year — a significant milestone not just for Haida Gwaii, but for remote communities throughout B.C.

Across much of the province, B.C.’s mostly-hydropowered centralized electricity system blurs into the background, delivering easily accessible, relatively affordable power at the flick of a switch.

But Haida Gwaii’s archipelago off the Pacific Coast is truncated from B.C.’s grid, making it one of around 44 remote communities in B.C. most of which rely on diesel for their power. There, diesel is delivered perilously by trucks and tankers, and leaves toxins lingering in the air. It remains a problem that the province has promised, but so far failed, to fix. In 2017, B.C. announced a target to reduce diesel on remote grids by 80 per cent by 2030, a goal that currently appears far out of reach.

But this past December, Tll Yahda Energy, an independent power producer and a partnership between the Council of the Haida Nation, Skidegate Band Council and Old Massett Village Council, made a sizable leap when their two-megawatt solar project, Solar North, officially came online. It marks the first time in B.C. that an intermittent energy source like solar has made a sizable dent in a diesel-driven remote grid. 

Tll Yahda Energy’s two-megawatt Solar North project has the potential to displace about six per cent of Haida Gwaii’s current diesel usage.

“We expected to have to do some trailblazing,” Brennan, manager at Tll Yahda and a lead on the project, says. “But it was basically reinventing that entire trail.”

If all goes as planned, Haida Gwaii’s project will soon be joined by a stream of others, including the Ulkatcho First Nation’s completed four-megawatt solar farm in the Chilcotin Plateau, the Nuxalk Nation’s run-of-river hydroelectric project on the Central Coast and the Uchucklesaht Tribe’s efforts on western Vancouver Island to build a 750-kilowatt solar and battery-storage project, among many others. Many are in development and partially funded, but require more support to move forward.

But as federal and provincial governments’ priorities shift, there are signs the window could begin to close again. That could spell trouble for communities with in-between projects, and for Haida Gwaii, whose journey to displace diesel still has a long way to go.

‘This is not something we want to risk anymore.’

Since the first electric light in the Pacific Northwest beamed out over a harbour near Victoria almost 150 years ago, power and access to it have developed asymmetrically. Wires and transmission lines quickly fanned out across the province, etching their way across Indigenous territories, targeting congregations of settler populations and the bursts of resource extraction they tended to follow.

Elsewhere, and in many First Nations communities, electric power was scarce until it came by way of diesel generators, which use diesel-fueled pistons to produce a magnetic field, generating electricity. But diesel power comes at a high cost for ecosystems and communities.

In the early hours of October 13, 2016, the Nathan E. Stewart tugboat ran into one of the many rocks tracing the shoreline in Heiltsuk territory. By around 10 a.m. the next morning, the tug had sunk, spilling more than 100,000 litres of diesel fuel and other pollutants into nearby Gale Pass, leaving a rainbow-coloured sheen across the water.  

The tug was among many that haul diesel to generators along the coast, including to Haida Gwaii. 

It was yet another alarm bell that propelled the nation’s resolve to get off diesel, Brennan says. “That was really what led to us saying ‘This is not something we want to risk anymore.’”

Because of its reliance on diesel, Haida Gwaii produces about three per cent of emissions caused by electricity generation in B.C., despite having only a few thousand residents. The B.C. government has set a goal of reducing diesel use on remote grids by 80 per cent by 2030.

On a regular basis, Haida Gwaii is visited by barges carrying diesel up through the Inside Passage and then through the Hecate Strait, which has been called the most dangerous water body on Canada’s coast, threatening ocean ecosystems and the nation’s coastal economy that depends on them. Even on land, diesel fuel tends to splatter and spill despite its handlers’ best efforts, leaving contaminated soil at loading docks and generating stations.

In the air, combusted diesel fumes produce pollutants like nitrogen dioxide and fine particulates, known to exacerbate asthma, cancer and risk of premature death. It also releases copious amounts of carbon dioxide. Haida Gwaii represents around three per cent of the province’s electrical emissions.

The Haida Nation’s work to shift from diesel galvanized in the mid-2000s, Brown explains. Community members tallied data across communities and realized the true scale of their diesel demand.

The Solar North project is an expression of energy sovereignty for the Haida Nation, which owns it in its entirety.

Inertia, political will posed challenges for transition away from diesel in B.C.

In theory, the province was also concerned about the amount of diesel being burned in remote communities.

Gordon Campbell’s Liberal government made the first move, directing BC Hydro to take over energy provision in additional remote communities, including some remote First Nations that had been operating their own energy systems with federal funding. Ideally, BC Hydro would help communities bring more clean energy to their grids. 

But that’s not what happened. 

The utility housed some deep-rooted inertia, according to Nick Hawley, a former manager on remote community electrification for BC Hydro at the time.

“They had diesel mechanics and diesel electricians,” Hawley, now an energy consultant, says. He describes an institution that was risk-averse and reticent to change. “They knew diesel.” 

As a monopoly utility, BC Hydro decides where and when it buys power, and from whom in the regions it services. It held prospective renewable projects to a strict test: It would only consider those that could beat the price of diesel fuel, not including the substantial costs of maintenance and replacing things like generators. They also required that projects cover the often sizable cost of connecting to the remote grid. Under those circumstances, says Hawley, it was difficult to get new renewable projects through.

In 2012, BC Hydro put a call out for energy projects on Haida Gwaii. Old Massett Band Council was one of many renewable projects that applied with a proposal for a 5.6 megawatt wind project. None were accepted.

The Haida Nation’s desire to phase out diesel galvanized in the mid-2000s, says Kevin Brown, seen here discussing energy projects at a community open house.

The Haida Nation had begun moving forward anyway. 

“We’ve been on a long journey,” Nangkilslas Trent Moraes, deputy chief councillor of the Skidegate First Nation, says. Communities started out working on smaller changes, beginning with things like solar water heaters and heat pumps. Soon, solar panels popped up on roofs across the islands, including the Haida Heritage Centre built in 2017 — B.C.’s largest community-owned renewable energy installation at the time. 

“That was the beginning of how we got into the power field,” he says. 

Still, the communities’ long-held goal of owning and operating a larger-scale renewable project remained out of reach. 

That changed when, beginning in 2019, Haida Gwaii’s southern band council, Skidegate, and northern council, Old Massett, began meeting to discuss energy issues with the Council of the Haida Nation. 

Together, the bands and nation pooled their efforts and resources, enabling them to pursue a project that wouldn’t have been possible in isolation. This allowed the nation to remain the project’s sole owner and decision-maker, absent the influence of investors or other companies. 

“I was thankful that we were able to acquire ownership for this project and not have third parties involved,” McEvoy, former chair of energy on the Tll Yahda board of directors and energy consultant for the Council of the Haida Nation, says.

Haida Gwaii is regularly visited by barges carrying diesel through the dangerous and ecologically sensitive Hecate Strait. A 2016 diesel spill in Heiltsuk territory was a wake-up call for the community. “This is not something we want to risk anymore,” says Tll Yahda Energy’s manager Sean Brennan.

BC Hydro had long argued that its ability to spend more on remote grids was constrained by the utility regulator’s legal requirement that new projects not unduly impact other ratepayers, a challenge for some renewable energy projects. As the plans for Solar North came together, McEvoy worked with a group of remote First Nations communities advocating for legal change, designing an amendment to remove that potential obstruction: for a temporary period, cabinet could now direct the utility regulator to accept these projects, even if they came at a higher cost than diesel.  

“That was a lot of blood, sweat and tears,” McEvoy says. The regulatory amendment was finally passed in 2024, and will remain until the end of 2029.

Together with other First Nations, Patrika McEvoy advocated for changes that would make it easier for the utility regulator to accept renewable projects in remote communities, like Haida-owned Solar North.

BC Hydro now had a clear legal runway to support renewable projects in the 14 remote grids — called “non-integrated areas” — it services. But the clock was ticking: the amendment was passed six years after B.C. set a target to reduce 80 per cent of its diesel emissions by 2030, and no projects in BC Hydro’s service regions had been achieved. Last December, Haida’s project became the first, soon to be followed by a solar farm in Anahim Lake led by the Ulkatcho First Nation, which is set to come online this year. Meanwhile, remote communities who had operated their energy systems independently had collectively reduced their diesel use by 84 percent since 2019, mostly through small hydroelectric projects.

In an emailed statement, BC Hydro said that it “took time” for the utility to incorporate new communities into its operating practices, to “ensure that the levels of reliability are brought to utility standards” adding that the remote grids they service tend to be larger and more complex to decarbonize than independently operated remote energy systems. It also added that since 2018 BC Hydro has been working with new sources of federal and provincial funding “to support a more cost-effective transition from diesel to renewable energy.” It also added that the province’s 2030 diesel reduction target is “not BC Hydro’s target.”

But by the time the legal amendment came in 2024, Tll Yahda’s work on Solar North was already well underway, having decided on a utility-scale solar farm on the north grid in an already-disturbed area near the airport. They ensured training opportunities were available for members, and hired 16 solar installers on the island, says Brennan.

Then they began to build.

The invisible wall

Even as the panels were placed and the wires hooked up, there was another problem to solve before Solar North’s diesel-replacing potential could be fully realized: it needed a place to store its energy. 

Electricity is notoriously finicky, requiring a steady stream of electrons delivered through conductive wires at all times to work well. When these electrons falter or pile up, lights flicker, clocks fall out of date, or, in more severe cases, the power can drop or surge, frying appliances.

Remote grids like Haida Gwaii’s are particularly hard-pressed to avoid such swings.

Improving battery technologies have enabled renewable energy sources to become more viable as a diesel replacement in recent years. But remote communities still face barriers to completely displacing diesel.

Imagine a concert-goer attempting to crowd-surf in a room of just three people: if one person trips or someone else decides to pile on, the effort could easily collapse. Similarly, a remote grid with just a few power sources can fail if one of its inputs suddenly drops out or an entire community turns on their dishwashers at once. On the other hand, B.C.’s large, interconnected grid has the resilience of a packed concert hall — disruptions like these are almost imperceptible. 

On-again, off-again renewables like solar and wind are particularly unpredictable, whereas the on-demand qualities of diesel fuel are more likely to hold weight when needed. 

Luckily, solutions have arrived. “The technologies have evolved very rapidly,” Mark Mitchell, global lead of distribution and smart grid at the consulting firm Hatch, says. Mitchell adds that, in remote communities, storage systems like lithium-ion batteries and microgrid controllers are newly equipped to smooth out such dips and surges. 

“It’s really been one of the main enablers for bringing more renewables online.”

For BC Hydro and for the Haida Nation, grappling with these cutting-edge storage systems was new: they had to decide who would own the battery and control systems — BC Hydro would in the end — and who to buy it from, a challenge thanks to limited supply chains for systems scaled to the needs of small, remote communities. 

“BC Hydro had never done a project where it’s connecting a renewable energy project to a diesel grid before,” Brennan says. 

“We didn’t realize all the implications that went with that.”

Today, Solar North is still waiting for its battery system to be installed. In the meantime, it’s displacing around 70 per cent of the diesel it is capable of. 

And when it’s expanded to match the size of its battery and grid upgrades, Solar North has the potential to displace around six per cent of the island’s electrical diesel consumption. The Nation is currently working with BC Hydro to determine the sizing for an expansion of Solar North that could push that displacement higher still.  

In many remote regions, displacing 100 per cent of the diesel brings challenges that batteries alone still can’t fix, Mitchell says. Today’s batteries are ideal for short-term storage, which can help even out daily dips and lows in solar power, but not longer seasonal shifts like Haida Gwaii’s stormy winters, when the sun is in short supply. 

“Essentially, what we’re going to do here is run into an invisible wall with solar,” Brennan says. At that point, solar energy will produce diminishing returns. 

Tll Yahda is studying ways to make solar work better for their communities, including a pilot project to test how solar panels matched with small-scale batteries could make the system run more efficiently. It’s also conducting analyses to test out how hybrid combinations of renewables behave on the grid.

The transition to renewable energy has produced economic opportunities in Haida Gwaii. Tll Yahda hired 16 solar installers on the island, according to Sean Brennan.

In renewable electricity, the right kind of complexity is key, Garrett Russ, climate action coordinator with the Skidegate Band Council, says. “I’m looking at this whole system as a whole complete project.” 

He’s seen the consequences of siloed efforts, including the nearly 50 heat pumps in his workshop that need fixing — thanks in part to a lack of trained workers on the island to keep them in good repair. Russ has since launched a training program, teaching Haida and other remote community members in B.C. how to maintain the systems while providing needed employment. 

A birds-eye view is a challenge because of project-by-project funding cycles and governments that tend to move in slow, incremental steps, Russ says. But he’s making the most of the opportunities he can create, and studying how wind and solar could work together. 

Whether operating independently or with BC Hydro, remote projects require funding, and Russ worries that the door may be about to close. Already, a key federal program has not had its funding renewed. In an emailed statement, Natural Resources Canada confirmed that funding through a key diesel-reduction grant program will end next year, but added that there are other “ongoing programs” that will continue to support the effort. 

“I believe there’s going to be a very significant cut possibly coming up,” Russ says. In preparation, he is working on as many projects as he can “in a very short time.”

“If that does happen, then at least I changed as much as I could.”

‘We have to keep going.’

A ten-minute walk from the arrow-shaped panels of Solar North sits B.C. Hydro’s diesel generating station, ringed in the spring by salal and salmonberries that McEvoy makes sure to avoid. 

Diesel still helps power Haida Gwaii’s grid, but the work to reduce it continues.

McEvoy and others across the islands have been asking their community members what kind of energy transition they’d like to see. Meanwhile, BC Hydro has begun to do energy planning with remote communities — for the first time in its history. The process design for those plans fell short of what many nations had hoped for: it doesn’t have legal standing, and remains, in many ways, on the utility’s terms. McEvoy says it remains an important step.

Haida Gwaii still burns diesel to generate much of its electricity — but the community is continuing to push forward.

McEvoy likens the process to paddling a canoe in a stormy ocean. “All we can see is dark, black clouds ahead,” she says. “We have to keep going.” 

At some point, she says, the clouds will break. 

“That’s us, and the work we’re putting in.”

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.

The Port of Cleveland is one of the main backers of offshore wind on the Great Lakes. Photo: Stephen Starr / Great Lakes Now

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?”

John Lipaj, a board member of the Lake Erie Foundation, is concerned about the impact offshore wind turbines might have on birds, such as the bald eagle. Photo: Katherine K.Y. Cheng / The Narwhal

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.

Wind turbines generate electricity near the shore of Lake Erie. But so far, none have been built on the water itself. Offshore wind has the potential to supply 100 per cent of Ontario’s electricity demand, according to Jack Gibbons of the Ontario Clean Air Alliance. Photo: Matt McIntosh / The Narwhal

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.

Across British Columbia, a growing number of Indigenous communities are developing sustainable power sources that balance local needs with environmental and economic concerns.

Freelance journalist Zoë Yunker, B.C. reporter Steph Kwetásel’wet Wood and Indigenous journalism fellow Santana Dreaver shared insights from their reporting for The Narwhal’s Generating Futures series at a public webinar on March 24. The conversation was moderated by Michelle Cyca, bureau chief, conservation and fellowships.

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.

Nearly all the energy that enters data centres like Digital Crossroad in Hammond, Indiana, on the shore of Lake Michigan, emerges as waste heat. Recycling this energy could reduce costs and the climate impacts of dumping the heat — in the form of warmed water — into the Great Lakes. Photo: J. Carl Ganter / Circle of Blue

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.

The Palisades nuclear plant in Covert Township, Michigan, shuttered in 2022. But Holtec, the plant owner, is preparing to restart the facility and to build a pair of small nuclear reactors on the site. As the Great Lakes region expands its energy capacity, advocates for waste heat reuse would like to see it incorporated into the design of new power plants. Photo: J. Carl Ganter / Circle of Blue

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

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

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

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

Barriers to entry

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

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

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

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

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

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

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

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

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

Summary

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

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

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

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

Sooo, what’s really happening?

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

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

Let’s dig in. 

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

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

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

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

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

What does the data on new renewable energy projects show?

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

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

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

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

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

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

Wind projects have seen a marked decline in Alberta in recent years, likely linked to the province introducing a moratorium on renewable projects in 2023, followed by stricter regulations. Photo: Gavin John / The Narwhal

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. 

Nathan Neudorf, minister of affordability and utilities, told The Narwhal 16 renewable energy projects were approved by the Alberta Utilities Commission in 2025. But a recent report by the Business Renewables Centre-Canada shows purchase agreements between companies looking to buy renewable power and renewable developers have declined dramatically. Photo: Jason Franson / The Canadian Press

“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. 

The slowdown in renewables growth and investment in Alberta can’t be attributed to one thing directly, but there’s no question multiple regulatory and market changes are having an impact. Nearly three years after a moratorium on new projects, followed by strict new regulations, the pace of investment has undoubtedly shifted. Photo: Amber Bracken / The Narwhal

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 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.

As a study in troubled operation, the Palisades Nuclear Plant once was ranked by the United States federal government as one of the four worst-performing nuclear power stations in the country. The 51-year-old facility closed in 2022, joining Big Rock Point near Charlevoix and 11 other nuclear plants decommissioned outside Michigan in what appeared to represent the sunset of the era of splitting atoms to produce electricity.

Not so fast. Sometime in the next few months, a New Jersey-based company called Holtec International is expected to finish renovating Palisades, fire up the old reactor and add 800 megawatts of generating capacity to Michigan’s electricity supply. It would be the first time a decommissioned nuclear plant has ever restarted in the United States. 

And that’s not the only game-changing nuclear development occurring at the Palisades site along the Lake Michigan shoreline in the state’s southwest corner. Holtec is busy seeking permission from the Nuclear Regulatory Commission, the United States’ licensing and safety agency, to start construction for a new 680-megawatt nuclear generating station next door to the old reactor. The company wants to power the new plant with not one but two 340-megawatt advanced small modular reactors.

So-called “SMRs” are now viewed by the industry, government, utilities and big energy consumers as one of the go-to electrical generating technologies of the 21st century. Holtec’s planned Pioneer I and II small reactors, and its Palisades reactor restart, signal the opening of a new era of electrical supply and demand in the Great Lakes basin. 

Holtec’s commitment to nuclear power, like other developers in the U.S. nuclear sector, is motivated by several converging and unconfirmed projections that are prompting billions of dollars in investment. By far the most important are that the cost of building nuclear plants will fall, and that demand for electricity will significantly increase. Nuclear developers and utility executives have embraced both optimistic scenarios, especially that electrical demand could increase as much as 50 per cent by mid-century, driven by data centre construction, new manufacturing plants, growing cities and electrified transportation. Both of Holtec’s projects in Michigan, and several more developments by other companies in Wisconsin, Ohio, Illinois and Ontario, are giving nuclear power new purchase in the region’s energy landscape.

The Government of Ontario has identified the Wesleyville Power Plant, seen here on the shore of Lake Ontario, as a candidate for new nuclear power generation. Photo: Bryan Dickie / The Narwhal

One of the most influential supporters is Michigan Governor Gretchen Whitmer, who is positioning Michigan at the lead of the nuclear revival era. She declared in a statement that opening Palisades and adding the small modular reactor plant “will lower energy costs, reaffirm Michigan’s clean energy leadership and show the world that we are the best place to do business.” 

Whitmer signed legislation in 2023 mandating that 100 per cent of the state’s electricity come from “clean power” sources, among them nuclear energy. Michigan awarded Holtec US$300 million to restart Palisades, a portion of the public funding package that included US$1.52 billion in loan guarantees from the U.S. Department of Energy. The Energy Department also awarded Holtec US$400 million more to develop the new SMR plant.

A study of small modular reactor development by the Department of Energy in 2023 found that construction costs for the first plants, like the one Holtec is planning, will be high because of limits on the supply chain providing parts, construction experience and unknown interest rates for financing. At current estimates of SMR construction costs of US$12 million to $15 million per megawatt, Holtec’s 680-megawatt plant could be put into operation at a cost of US$7 billion to $10 billion.

Michigan’s bid to stimulate new markets for nuclear energy, moreover, are still dogged by old concerns about safety, waste management and the cost of construction and operation. Three public interest groups filed a federal lawsuit in November asserting that opening the old Palisades reactor was illegal and unsafe. The case is pending in Federal District Court in Grand Rapids.

Safety, cost and waste addressed

By any measure, managing high-level radioactive waste from commercial reactors has not changed much in the last half century and persists as an issue because no permanent waste repository has been established in the U.S. But other considerations of the risks, benefits and cost of nuclear power are tilting in new directions, especially for SMR plants like the one Holtec is proposing in Michigan. 

Small modular reactor developers make a consistent case for proceeding with the new technology.

Nuclear waste site assessment begins in northern Ontario

Water consumption looks to be an environmental advantage, particularly in water-abundant regions like the Great Lakes. Holtec’s environmental statement filed with the Nuclear Regulatory Commission reports that the two reactors will draw 95,000 litres a minute for operation — as much as 135 million litres a day. At that rate the new plant, which is 15 per cent smaller than the existing Palisades plant, will withdraw 75 per cent less water. 

Because of its more compact 50-hectare footprint, the new Holtec plant would easily fit onto the 175-hectare site that already encompasses the existing reactor. It will transmit electricity with the existing powerlines and infrastructure. And like other commercial reactors, small modular reactors don’t discharge climate-warming gases, a big factor in why nuclear power has gained considerably more support in public polling in recent years.

When it comes to operational safety, Holtec and other SMR plant developers say their designs also answer that concern. The advanced modular reactors are smaller and contain less fuel, produce lower levels of radiation and can operate at a lower temperature and pressure than big conventional reactors. Those properties enable engineers to design a reactor that can be cooled with water or air, and can be shut down with gravity-fed systems that don’t rely on mechanical pumps. 

“When it comes to safety the question is, ‘How do I keep this cool?’ ” Brendan Kochunas, associate professor of nuclear engineering at the University of Michigan, said. “And that comes back to the amount of fuel that you have in the core. SMRs have smaller cores. There’s less heat being produced so you need to remove less heat.”

The energy boom is coming for Great Lakes water

Industry executives assert that because the reactors are smaller than conventional 1,000-megawatt plants, they will require fewer construction materials, take fewer years to build and be less expensive to operate. Industry executives say their goal is to standardize designs so that parts can be manufactured and new reactors can be assembled and shipped on trucks or by rail. And because SMR plants have multiple reactors, one can be shut down for maintenance while the others continue operating. 

“In discussions we’ve had about small modular reactors, there may be lower upfront costs and potentially faster deployment because you don’t have quite as much concrete,” Scott Burnell, the spokesperson for the Nuclear Regulatory Commission, said in an interview. “And once you get into operation, the concept is you’ve got several small reactors running. If you bring one down for maintenance, you still have others running, generating profit.”

Race for orders

Holtec is competing with 30 other small modular reactor developers in the U.S. to be among the first to bring its reactor to market. Patrick O’Brien, the Holtec spokesperson, explained that the company has spent 15 years designing the SMR-300, preparing architectural plans for the generating station and keeping the regulatory commission informed of its activities. Though the SMR-300 has not received an operating licence, O’Brien said Holtec is confident it will be approved and the plant would be operating in 2032. “A lot of the work was done up front,” he said. “We’re anticipating two and a half more years’ worth of licensing work from the [Nuclear Regulatory Commission]. And two and a half years of construction.”

That’s an optimistic schedule for new nuclear plants. NuScale, an SMR designer based in Oregon, licensed its first 66-megawatt reactor with the regulatory commission in 2023. It has yet to build a new plant. NuScale’s first project to install seven small modular reactors at a 462-megawatt plant in Idaho collapsed after construction cost estimates increased from under US$4 billion to more than $9 billion. 

The NuScale experience reveals that uncontrolled costs are a primary impediment not just for big traditional reactors but also to SMR development. Small modular reactors don’t exist in North America or Europe, and just three operate in the world — two 35-megawatt reactors operating on a ship in Russia and a third 125-megawatt small modular reactor in China. “One always has to remember that these are experimental technologies,” Joseph Romm, a physicist and senior research fellow at the University of Pennsylvania, said. “Both the Russian and Chinese reactors had huge cost overruns.”

What does a ‘nuclear renaissance’ mean for uranium mining in Saskatchewan?

According to an important study published last year by the University of Michigan, small modular reactors also may produce new environmental risks that could attract more review. Small reactors, for instance, have the potential to introduce new and unregulated byproducts and increased levels of radioactivity due to the demand for highly enriched uranium fuel, according to the report, The Reactor Around The Corner.

Another likely environmental risk is deploying small reactors to power big industrial projects in the world’s wild and undeveloped places. Small modular reactors pack a lot of energy into a small and portable power source, said the report’s authors, who projected that the small reactors will enable construction of big mines and industrial plants in terrain that has been too expensive to reach or entirely inaccessible. “SMRs will introduce and exacerbate direct and indirect environmental harms, especially on marginalized communities, that complicate the justification for using them to mitigate climate change,” they wrote.

Midwest familiarity with atomic technology

To date, elected leaders and residents in Michigan and the other Great Lakes states have responded to the opening of a new era of nuclear development with much more enthusiasm than alarm. That may be due principally to the region’s pioneering role in fostering atomic energy. The first nuclear chain reaction occurred at the University of Chicago in 1942. Argonne National Laboratory opened in Illinois in 1946 to serve as the centre of atomic research and technology development. The Shippingport Atomic Power Station in Pennsylvania opened in 1957 as the first commercial nuclear generating station.

Not since the height of commercial nuclear energy construction in the 1960s and 1970s have Great Lakes states seen such a concentration of new nuclear projects either underway or planned. The Palisades restart would push the number of operating nuclear reactors in the eight states to 24, second only to the more than 30 big reactors operating in the six southeast states.

In addition to restarting the decommissioned Palisades Nuclear Plant in Michigan, Holtec International is proposing a new small modular reactor, or SMR, on the site as well. With supportive federal policy in place, the company says the SMR could be operational by 2032. Photo: Supplied by Holtec

More big reactors could be on the way. DTE Energy notified the Nuclear Regulatory Commission last year that it is actively studying the development of a new reactor at its Fermi Nuclear Generating Station south of Detroit along Lake Erie. 

Small modular reactor plants, too, are attracting attention in the Great Lakes basin. Ontario Power Generation is constructing a 1,200-megawatt plant, composed of four 300-megawatt SMRs, at its Darlington Nuclear Generating Station along the shore of Lake Ontario. It could be the first operating commercial SMR plant in North America. 

Utah-based EnergySolutions is proposing to build “new nuclear generation” along the Lake Michigan shoreline in Wisconsin at the Kewaunee Power Station, which closed operation in 2013. Oklo Inc., a California company, is proposing a small modular reactor in Portsmouth, Ohio, where a closed federal plant once enriched uranium for nuclear weapons. The University of Illinois notified the regulatory commission that it is developing a gas-cooled SMR research reactor at its campus in Champaign-Urbana. 

The surge of interest is the second time this century that utilities, government and investors have tried to revive nuclear power in the U.S., and is driven by many of the same factors. One is federal policy to promote nuclear projects. The second is a tide of government financing that can be traced back to 2021 when then-president Joe Biden signed the US$1.2 trillion Infrastructure Investment and Jobs Act that directed US$8 billion to nuclear energy. Three years later, Biden signed the ADVANCE Act to make it easier and less expensive for nuclear plant developers to license their designs with the Nuclear Regulatory Commission.

President Donald Trump also supports nuclear energy. He signed four executive orders in 2025 to accelerate the deployment and integration of advanced nuclear reactor technologies, and directed federal agencies to take aggressive action to build a nuclear production industry to mine and enrich uranium and construct manufacturing plants to fabricate fuel, reactors and parts. Earlier this month, the Department of Energy exempted small modular reactors from National Environmental Policy Act review. 

Westinghouse late last year signed an agreement with the U.S. government to build ten 1,000-megawatt reactors in the U.S. That agreement is tied to the pact that Trump reached with Japan last October to finance US$332 billion “to support critical energy infrastructure in the United States,” including the construction of ten Westinghouse AP1000 reactors and small modular reactors. The president also wants to develop the capacity to recycle nuclear fuel to reduce highly radioactive waste. 

Trump’s goal is to quadruple electrical generation capacity from nuclear power from 97 gigawatts today, powered by 94 operating reactors, to 400 gigawatts by 2050.

In the last five years, Congress has enacted more than US$20 billion in direct appropriations for nuclear energy programs, along with tax credits and federal loan authority that add billions more in federal support for existing and advanced reactors. 

U.S. technology giants like Amazon, Google, Meta and Microsoft also are getting involved.

Company executives are establishing formal agreements with nuclear developers to build and buy power for their data centres. Meta, for instance, has an agreement with Oklo Inc. to build a proposed 1,200-megawatt small modular reactor plant in Ohio. The high-tech stalwarts also joined 14 major global banks and financial institutions, 140 nuclear industry companies and 31 countries in signing a pledge last year in Texas to support tripling global nuclear capacity by 2050.

Just marketing?

The big unknown is how much of this fervour is grounded in reality, and how much is hype and marketing. During the last attempt to revive nuclear energy in the U.S., from 2007 to 2010, the Nuclear Regulatory Commission counted over 20 nuclear plant proposals to review. But the heat of atomic hope quickly cooled as fracking started to produce ample supplies of natural gas, and much less expensive wind and solar power was gaining momentum. Just two new reactors that started construction during that period actually got built and began operating at Georgia Power’s Plant Vogtle. It took the utility 15 years to finish the project in 2024 at a cost of more than US$30 billion. 

“Some vendors are overselling the vision,” Kochunas of the University of Michigan said. “I hope we do see some SMRs. They still have challenges in their economics. For it to succeed, one of these companies is going to need to establish a pretty substantial order book.” 

Could that be Holtec? 

“Yes,” Kochunas said. “I think they’ll get that built in Michigan. If they execute the project successfully, they will have opportunities to build more of them. Hopefully, you’ll see people lining up to get them. But if the execution of the project goes poorly and there’s significant delays and cost overruns and problems, it’s going to be hard to change that first impression.”

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.

2026 has already had its fair share of geopolitical chaos: Alberta separatists meeting with U.S. officials, everything happening in the U.S., global retreat from emissions reductions, Greenland. The list goes on.

But that’s not all that’s ringing in the new year. There are plenty of real things happening within the confines of Alberta, from the government’s continued pushback against emissions reductions to continued promotion of hunting and, of course, the seemingly unending conversations about pipelines. 

Let’s dig into what’s been happening in Alberta since the start of this year.

Alberta is looking to borrow big money

Why does an Alberta government agency need to borrow nearly $1 billion?That’s a very good question — one even the former head of that provincial agency is asking.Last year, the government announced it would allow oilsands producers to pay their royalties with barrels of bitumen, instead of cold, hard cash — known as Bitumen Royalty In Kind, or BRIK. 

It’s something the government has done on the conventional oil and gas side for years. 

When a company opts to pay with barrels, the Alberta Petroleum Marketing Commission sells those barrels on the open market. That money then goes to the government. 

Last week, however, the government quietly authorized the commission to borrow as much as $900,000,000 for “hydrocarbon marketing activities.” 

It also (and apologies in advance, because this is long and boring — but important!) “approves the Alberta Petroleum Marketing Commission purchasing shares, making loans, entering into joint ventures or partnerships or providing guarantees for hydrocarbon marketing activities,” and “authorizes the Alberta Petroleum Marketing Commission to incorporate or acquire one or more subsidiary corporations for hydrocarbon marketing activities.”

Alberta really wants a new pipeline to the West Coast, even if no private company wants to build it. It has already committed more than $14 million to push the project through early planning stages, now some are wondering if a new billion-dollar government tab could be committed to pushing it even further along. Photo: Marty Clemens / The Narwhal

That means the commission can borrow almost $1 billion to shore up companies, provide financial security and more. Why should the Alberta Petroleum Marketing Commission have to borrow money if all they’re doing is getting oil for free (instead of royalties) and then selling it? And why do it now? 

Richard Masson, a fellow at the University of Calgary’s School of Public Policy and former head of the commission, came right out and said this could be a way for the Alberta government to either backstop a new pipeline project, or try to buy more oil to spur more production because there’s not actually enough oil to fill all these new pipelines and expansions. 

Either way, the government is still amped to push for a new pipeline through B.C., unveiling a new website to act as a central hub of (questionably objective) information on the project, which, if you remember, still doesn’t have a company that wants to build it. 

Perhaps $1 billion will help change some minds. Also, reminder, the province burned $1.3 billion backstopping the failed Keystone XL project. 

An Alberta minister travelled to Montana to talk about electricity

In Alberta, there’s never a shortage of things to talk about when it comes to keeping the lights on. 

Minister of Affordability and Utilities Nathan Neudorf travelled to Montana in January to talk about grid reliability and working with neighbours. 

Nathan Neudorf, the minister of affordability and utilities, travelled to Montana to talk about how important it is to connect electricity grids across borders. Meanwhile, the state has filed a formal complaint with Alberta’s utility regulator, accusing Alberta of restricting the flow of electricity across its border. Photo: Government of Alberta / Flickr

“Meeting rising electricity demands means looking beyond our borders,” he said in a news release. “Powering up our electrical ties with Montana is about building a strong foundation for shared energy security, while ensuring that the electricity Albertans depend on remains reliable and affordable for generations.”

Unfortunately, Montana is a wee bit miffed at Alberta at the moment and it’s all because the province isn’t working with its neighbours. 

The state says Alberta is restricting the flow of power on its cross-border connection (known as interties) and the company which owns the line has filed a complaint against the province with the Alberta Utilities Commission. 

The issue has also been raised by the Trump administration as a trade irritant. 

Alberta denies the claims, but it is facing similar complaints from B.C. Meanwhile, on its eastern border, the intertie with Saskatchewan was down for about a year, but has now resumed operations. 

‘Increasingly concerned’: docs show B.C. government pushed back on Alberta electricity restrictions

And another Alberta minister went to Nevada to auction off a hunting licence

Todd Loewen, the minister of forestry and parks, and a hunting enthusiast, returned to Nevada for the Wild Sheep Foundation Sheep Show in January for the third time to hype his annual auction of a special licence to hunt bighorn sheep in Alberta. (Yes, lots of sheep in that sentence.) 

Last year, the auction raised $400,000 to ensure there’s at least one less sheep in the world. 

Alberta is (again) musing about nuclear power

The provincial government, whose policies have effectively killed the most robust renewable electricity market in Canada, wants to hear what Albertans think about building nuclear power in the province to help, uh, generate clean electricity. 

Investment in renewables plunges in Alberta

A panel, which includes a United Conservative Party MLA and a former NDP MLA, will listen to public feedback and prepare a report of the government at the end of March. The last panel hosted by the province resulted in the executive director of the Alberta premier’s office telling a high school student he should be spanked. So, you know, I guess these things are never boring?

Albertans are still mad about coal mining

Alberta musician Corb Lund has successfully submitted a citizen’s petition against coal mining on the eastern slopes, after his previous petition was scuttled by the province changing the rules. 

A dump truck works at Teck’s Fording River Operations coal mine in B.C. The mine is just across the border with Alberta, where the government has opened the door to new mines decades after the practice was essentially banned from the eastern slopes of the Rocky Mountains. Photo: Jesse Winter / The Narwhal

Lund has been an outspoken critic of the government’s plans to reopen a stretch of the Rocky Mountains to new coal mines, warning it threatens the water supply and the livelihood of ranchers. 

Musician Corb Lund on Alberta coal mines: ‘they’re going to ruin our ground water’ 

The petition calls for the province to legislate against all “coal exploration and mining activities” on the eastern slopes for mines that aren’t already producing coal as of Jan. 1, 2026, and any mine expansions.

The petition still has some bureaucratic hoops to jump through before Lund can rally canvassers to collect signatures.

Alberta is full-steam ahead on data centre proposals

The largest data centre in Canada could be built in Olds, Alta., which the company, Synapse Data Centre, says will involve a $10-billion investment, including its own gas power plant and promises of a closed-loop water system that will reduce the plant’s thirst. 

That’s different from the one you might recall that was announced by Kevin O’Leary in December 2024 — a data centre more than 32 times the size of the largest data centre in the world — which is still nowhere to be found.

The AI data centre boom is here. What will it mean for land, water and power in Canada?

Data centres consume huge amounts of energy and water. The Alberta government thinks they’re great and wants to see $100-billion worth of them across the province. 

Of course, there’s that little issue of not having enough electricity to actually power all those centres, so the province introduced legislation to allow developers to build their own supply, like the on-site natural gas plant in Olds. 

“We see this enormous opportunity to grow our tax base, to grow domestic demand for our natural resources,” Nate Glubish, the minister of technology and innovation, said while announcing the changes. 

Updated on Feb. 5, 2026, at 11:10 a.m. MT: This story has been updated to correct an error. The nuclear power consultation panel includes one United Conservative Party MLA (Chantelle de Jonge), not two. It also includes a former NDP MLA, Deron Bilous.

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.

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

But the province had a powerful ace up its sleeve.

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

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

Six Nations’ huge battery project is the future of energy supply in Ontario — and maybe all of Canada

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

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

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

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

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

By storing energy produced during off-peak hours from renewable sources like wind and solar, battery facilities can help reduce the reliance on emission-heavy gas plants. Photo: Supplied by Northland Power

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

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

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

Trio of projects pitched for Norfolk County in southern Ontario

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

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

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

Energy storage facilities absorb excess power during times of plenty, and then return it to the grid when demand begins to outpace supply. Photo: Alex Jacobs-Blum / The Narwhal

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

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

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

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

Is B.C. sidelining community power? Why co-ops struggle to compete in the energy sector

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

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

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

Oneida ‘proved the hypothesis’

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

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

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

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

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

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

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

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

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

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

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

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

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

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.

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

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

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

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

Quatsino First Nation installed solar panels at its daycare early in 2025.

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

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

Quatsino has a partnership with a wind farm, is completing its own solar project and launching a tidal power pilot project. Kara Wilson, Quatsino’s energy champion, is excited by opportunities to expand nation-led renewable energy.

Challenges to launching small, local energy projects

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

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

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

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

A First Nation may only have the capacity to launch something smaller, but it can be challenging to get smaller projects funded, Kara Wilson says.

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

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

Is B.C. sidelining community power? Why co-ops struggle to compete in the energy sector

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

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

Quatsino’s solar project is projected to save the nation $18,000 annually in energy costs once completed.

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

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

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

Solar power inverter equipment at Quatsino’s daycare converts the direct current (DC) to alternating current (AC), the circuit type used for power grids and household electricity.

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

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

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

Nation is pursuing energy cost savings and independence

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

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

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

Quatsino First Nation Energy Champion Kara Wilson looks at solar equipment at the nation’s daycare.

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

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

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

‘This is the vision’: Inside Nlaka’pamux Nation’s quest to build B.C.’s first major solar project

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

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

Quatsino has worked with several funding partners to advance renewable energy. Quatsino’s school, pictured above, will have solar panels installed this year.

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

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

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

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

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

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.

Investment in renewables in Alberta has cratered due to government policies, according to a new report.  

The province was once the epicentre for clean electricity in Canada, but Business Renewables Centre-Canada, an organization that facilitates and tracks investment in renewable energy, says 2025 marked the first time in seven years that no new wind power was announced.

“New wind projects have stalled altogether,” reads the renewables in review report. “All projects currently under construction were commissioned by the end of 2024 and 2025 marked the first year without any reported wind capacity additions since 2018.” 

Solar power has also been hit hard, with the smallest annual growth in capacity since 2019 — a time when the sector was on the cusp of an investment surge.

Appetite for investing in electricity projects shifting ‘away from Alberta,’ say investors

Proposed renewables projects, including those that were ready to start construction, have been cancelled and new project proposals have disappeared, according to the organization. New corporate deals all but evaporated in Alberta in 2025, declining by 99 per cent compared to 2023.

The report puts the blame squarely on government policies and directives that have restricted renewable energy development and introduced significant uncertainty into Alberta’s private electricity market. The Alberta government did not respond to The Narwhal’s request for comment by publication time.

Sara Hastings-Simon, an associate professor in the department of earth, energy and environment at the University of Calgary, who helped found the Business Renewables Centre-Canada but is no longer attached to the organization, said the drop in investment isn’t surprising. 

“Renewable energy development is really a global market,” she said. “So jurisdictions are competing against every other jurisdiction out there for development. When the situation gets less attractive, you see capital going from being very interested to being very uninterested.”

Alberta once led the country in renewables investment

Alberta was once the darling of renewable power investment and growth in Canada, far surpassing other provinces as wind and solar projects multiplied. 

The driver was the province’s private electricity market and the ability of large corporations to sign agreements with renewable generators to buy all that clean power to lower or offset their own emissions. Those arrangements are called power purchase agreements.Power purchase agreements, which bankrolled renewable projects, were responsible for 60 per cent of Alberta’s renewable surge. The Business Renewables Centre-Canada estimates projects funded through these contracts since 2019 “have resulted in over $7 billion in capital investments and generated around 7,000 construction jobs, almost entirely in Alberta.”

Then, in 2023, the United Conservative Party government under Premier Danielle Smith shocked the industry by unilaterally implementing a moratorium on any new renewable energy projects for seven months — a move she said was in response to requests from the Alberta Electric System Operator, which was in fact opposed to the plan, and the utility regulator.

A senior Alberta official found the renewables pause ‘very troubling.’ He was pressured to support it anyway

Behind closed doors, Mike Law, the former CEO of the Alberta Electric System Operator, which oversees the electricity grid, had warned the government that its moves against renewables would send the industry into a “tailspin.” 

“If we make ourselves unwelcoming, investment will just go elsewhere,” he wrote.

Law later lost his job and was replaced by a government-appointed member of the operator’s board.

Alberta renewables moratorium was followed by major overhaul

The situation didn’t improve for renewable developers once Alberta’s moratorium was lifted, with the introduction of stiff new regulations that prevented projects in vast areas of the province. 

Shortly after that, the province initiated a hasty comprehensive overhaul of the electricity market that introduced more uncertainty, as well as new rules on transmission that will restrict the ability of renewable projects to earn a profit.

A report commissioned by the grid operator and published in 2025 centred on interviews with eight unidentified “major financial institutions” to gauge reaction to the operator’s massive overhaul of the provincial electricity grid. It appears to predict the investment vacuum outlined in the Business Renewables Centre-Canada report.

How does Alberta’s electricity grid actually work?

“This climate of uncertainty has increased the cost of capital, reduced appetite for new investments and led to delayed or cancelled projects,” reads the report, which was authored by consulting firm Morrison Park Advisors. “Some lenders reported that projects in advanced financing stages were paused or abandoned altogether in response to recent announcements.”The report says investor confidence in Alberta as a stable market has been “significantly undermined.”

In addition to the regulatory and policy hurdles, Alberta also weakened its industrial carbon price scheme and drove down the value of carbon credits, a key pillar to incentivize decarbonization and drive renewable growth. 

In an emailed response to questions from The Narwhal, the Alberta Electric System Operator did not take issue with the findings in the new Business Renewables Centre-Canada report, and pointed to the fact 92 per cent of Canada’s renewable electricity growth came from Alberta in 2023. 

It also highlighted a current oversupply of installed capacity on the grid and depressed prices, which could impact investments. 

“Low-cost renewable energy is important, but we also need to recognize there are also several reliability concerns stemming from rapid integration of renewables that must be addressed,” it said in a statement. 

The system operator said its market reforms are “intended to strengthen the reliability of the grid, improve cost outcomes for Albertans, and support investment in both new and existing technologies.”

Hastings-Simon, however, called the situation in Alberta a “perfect storm” of factors impacting renewables.

In 2025, solar power in Alberta saw its smallest annual growth in capacity since 2019. The outlook for renewable energy in Alberta in 2026 isn’t looking any better, according to a new report from the Business Renewables Centre-Canada. Photo: Leah Hennel / The Narwhal

To put the impact of those changes in context, Jorden Dye, the executive director of Business Renewables Centre-Canada said approximately 1,000 megawatts of renewable electricity was added to Alberta’s grid each year between 2021 and 2023. That number is expected to be around 200 megawatts this year. 

“If the market continues the way we’re at, I see it as it’ll be very specific projects that are able to go through — in the right spot at the right time — but that’ll be it,” Dye said.

Nova Scotia now leads the country in renewables investment

The outlook into 2026 isn’t any better, according to the Business Renewables Centre-Canada, which says there are “no active” projects backed by a power purchase agreement announced for this year. 

Wind, in particular, will likely continue to wither, and developers have “almost completely stopped advancing their projects.”

That said, the organization isn’t entirely pessimistic. 

It says solar projects that are ready to move forward haven’t completely pulled out of the development queue, but are waiting for more certainty before proceeding.

It also highlights the recent memorandum of understanding with the federal government over a West Coast pipeline that includes a commitment to strengthen the province’s industrial carbon price. That carbon levy could provide more incentive for power purchase agreements, but Alberta further weakened the scheme after signing the memorandum.

Dye also pointed to the promise of storage batteries as a means to blunt some of the impacts from new transmission rules. 

In the meantime, other Canadian jurisdictions are luring investment. Nova Scotia led the country in corporate power purchase agreements in 2025, usurping Alberta. But Dye said no one jurisdiction is in a position to replicate Alberta’s previous growth. 

Hastings-Simon said a lot of work went into attracting big renewable developers to Alberta, work that paid off with significant investments. But, she added, Alberta “dropped the ball,” and some of that — including the chilling impacts of the renewables pause — will be hard to reverse. 

“I think certainly things that are really unprecedented when it comes to government involvement in the market are probably the hardest to recover from,” she said.

Updated Jan. 27, 2026, at 4:45 p.m. MT: This story was updated to include comments from the Alberta Electric System Operator, which were received after the deadline.

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.

When the turbines began turning at Bear Mountain Wind Park in 2009, it became the first fully operational wind power project in B.C. The park’s 34 wind towers run along the crest of a rocky ridge just south of Dawson Creek, looking out over the flattening foothills of the Rocky Mountains. Together, the towers supply 102 megawatts of electricity to the provincial power grid, roughly enough to power 41,000 homes for a year.

The project marked a major milestone for the Peace Energy Cooperative, which spearheaded the development of the wind park. At that point, Don Pettit, the co-op’s executive director, was optimistic about the future of wind power and co-op energy projects in B.C.

“It was pretty good for our first go,” Pettit recalled. “It worked really well, so we assumed that we’d be able to do that in the future.”

But, despite Bear Mountain’s success and the expertise Peace Energy picked up while developing the project, things didn’t pan out that way. Big infrastructure projects are notoriously costly and there are restrictions on how much seed money co-ops — even investment co-ops like Peace Energy — can raise from their members. Peace Energy partnered with Aeolis Wind Power Corporation in the early stages of developing the project because the company had experience working with other co-ops. 

When it came time to build, the co-op raised capital from its members and struck a partnership with AltaGas, an energy company that mostly builds oil and gas infrastructure, to help cover construction costs. Then, Peace Energy faced a big choice: whether to maintain an ownership stake in the project and shoulder a share of the park’s maintenance and operating costs, or sell.

“We decided to go with a royalty agreement instead,” Pettit said, adding that the deal provides the co-op with a stable, modest income stream that helps cover its operating costs.

In Dawson Creek, Don Pettit and the team at Peace Energy Cooperative help their neighbours learn about and install solar power.

Since selling its stake in Bear Mountain, Peace Energy has focused mostly on community-scale solar power projects, including helping the District of Hudson’s Hope set up the largest municipal solar project in the province in 2018. Located just upriver from the Site C dam in the heart of B.C.’s oil and gas country, Hudson’s Hope now generates much of the power for its municipal buildings — anywhere from 50 to 100 per cent — from solar. The district estimates its solar power project saves $74,000 per year on electricity costs.

But Pettit still thinks of Bear Mountain Wind Park as a “precedent-setting example” of how renewable power can be developed in B.C.

“And that’s the last time it ever happened,” he told The Narwhal.

There aren’t many energy co-ops in Canada. A recent study by researchers at Royal Roads University found 82 active energy co-ops across the country. Together, they own or co-own 214 renewable energy projects. By contrast, there were 847 energy co-ops operating in Germany in 2023 while the Netherlands is home to 713 active energy co-ops.

Bear Mountain Wind Park produces enough electricity to power thousands of homes, but it’s also a public recreation site and a space where local ranchers can graze cattle. Preserving public access to the site was a priority during the development phase.

The gap between Canada and other countries is partly because not many provinces have policies that support small and localized energy generation. Instead, governments are used to working with big organizations that can invest big bucks into energy projects and infrastructure. It can be tough for small, community-oriented organizations to get a foothold in a system that favours larger, corporate entities. 

In a statement, B.C.’s Ministry of Energy and Climate Solutions said the province supports the growth of B.C.’s co-operative renewable energy sector and acknowledged energy co-op projects “can increase the energy resilience of neighbourhoods and communities.”

But Pettit believes the government underestimates the value energy co-ops bring to the table.

“The co-operative movement in energy in B.C., it’s ignored,” he said. “There’s no sense of, do we want local people to own local energy resources? I think the answer to that question, provincially, is no, we don’t. If they did, they would be encouraging co-operative involvement.”

What is an energy co-op? And why do we have so few of them?

Co-operative businesses — referred to as co-ops for short — are owned and run by a group of people who share common goals. Profits are shared among co-op members and decisions are made democratically, with each member getting one vote. While traditional businesses typically prioritize producing profits that can be paid out to shareholders, co-ops often have a social focus and seek to fill a need that isn’t being well served by the traditional market.

In Canada, co-ops are more common in some sectors. You may have shopped at a food co-op, lived in co-op housing or used a credit union. But energy co-ops are fairly rare.

“Where co-ops work well is where there’s a strong, intimate user relationship,” Martin Boucher, dean of research at NorQuest College and president of Community Energy Cooperative Canada, said.

Most people probably don’t feel as connected to their local power grid as they do to their local food supply, their home or the daycare their children attend. Electricity isn’t exactly a warm, fuzzy subject, even if it is essential. In B.C., the energy sector is highly centralized and pretty much everything electricity-related flows through BC Hydro, the public power utility created in the 1960s. 

BC Hydro is responsible for managing and maintaining most of B.C.’s power supply, from the massive hydro dams that generate electricity to the infrastructure that keeps the province humming.

“The logic of utilities, and rightly so, has been economies of scale,” Boucher said. BC Hydro and other Canadian power utilities have historically focused on building big electricity generation projects along with the infrastructure to deliver that power to customers, all while keeping electricity rates as low as possible. 

Don Pettit and other members of the Peace Energy Cooperative spent years working to make Bear Mountain Wind Park a reality.

B.C. is barrelling toward extensive electrification of its economy, including supplying power-hungry resource sector projects like mines and liquefied natural gas (LNG) facilities. Doing so will require a significant increase in the province’s power supply, one BC Hydro has not yet mapped out how to supply, according to its most recent resource plan. Boucher believes co-ops could help fill the gap.

“The kind of world we’re entering into is a high energy world with data centres, AI, electric vehicles, this sort of thing,” he said. “My baseline philosophy is energy diversification requires all hands on deck to really move this forward.”

Centralized electricity generation and distribution systems have served many communities well for decades, Boucher said, but they can be a barrier to co-operatively owned energy projects, which are often smaller scale with different goals than traditional energy companies. 

“They’re very antithetical to that kind of business model,” he said.

Because the energy sector is so highly regulated, co-ops interested in energy projects are “completely at the mercy of policy,” Boucher added.

In Canada, it’s fairly easy to see where energy co-ops have been encouraged.

Provinces without a public power utility like BC Hydro tend to have more renewable energy co-ops. Ontario, for instance, is home to roughly 75 per cent of Canada’s renewable energy co-ops while Alberta, with its open access electricity market and a strong tradition of co-op businesses, also has a relatively high number. 

“From the perspective of the electricity system, we might as well consider our provinces 10 different countries,” Boucher said. 

“There’s more alignment between countries in Europe on electricity policy and sharing than there are between provinces in Canada.”

Grid alerts: what you need to know as electricity demand ramps up in Alberta

Despite their differences, most provinces provide pretty reliable access to affordable power so there has not been a lot of demand for alternative options, according to Julie MacArthur, an associate professor in Royal Roads University’s faculty of management whose work focuses on energy transitions and the political economy of energy projects.

“Energy systems in general are not super top of mind to most people in a developed country, until you have huge power outages or there’s some problem with it or it’s too expensive,” MacArthur said.

“I think there are a lot of activities co-ops could be contributing to that they’re not because they’re not recognized necessarily as legitimate actors in this space or there’s not a lot of policy attention on them,” she added. “But in every province, the need is going to be slightly different.”

With the right support, community solar could offer B.C. a bright future, co-op co-founder says

With climate change boosting the intensity and frequency of natural disasters, co-op energy models could become more appealing to more people. On Galiano Island, the Salish Sea Renewable Energy Co-op was born out of residents’ desire to take concrete action on climate change and reduce their dependence on fossil fuels. Since 2015, the co-op has helped set up more than 110 solar power installations across B.C.’s Gulf Islands.

“We got sick and tired of just demonstrating and writing letters, and we actually wanted to do something,” Tom Mommsen, a founding member of the co-op, told The Narwhal. 

“We give talks, we do initial assessments. We help people to go solar and then we hand it over to commercial installers and they do the rest.”

Over the past 10 years, the Salish Sea Renewable Energy Co-op has helped set up more than 110 solar power installations across B.C.’s Gulf Islands. Founding co-op member Tom Mommsen sees solar as a powerful tool to help decarbonize B.C.’s power supply and empower people to better understand their energy use. Photo: Risa Smith

Solar power is by far the most popular form of energy for co-ops in Canada, accounting for 91 per cent of the renewable energy projects they operate.

Mommsen, a retired academic who still works with the University of Victoria’s School of Environmental Studies, spends a lot of time researching the latest solar energy policies and technologies so the co-op can share the information with community members.

Most people, Mommsen said, do not know much about the electricity that powers their homes and, in more and more cases, cars.

“Nobody understands what a kilowatt hour is,” he told The Narwhal. “Once these people have solar and they look at the solar production … they know very well what a kilowatt hour is. The best education is just to have solar in your backyard or on your roof.”

Support for solar can spread quickly, in Mommsen’s experience.

“Someone starts with solar and then a couple of years later, there will be five or six … neighbours with solar because they talk.”

More than 90 per cent of co-operatively owned renewable energy projects in Canada involve solar power. Photo: Province of B.C. / Flickr

Research bears out the knock-on effects community energy initiatives can have, MacArthur said. People may find it easier to trust the experiences of their friends and neighbours than the pitches made to them by government bureaucrats or private companies.

“If they get the information about it from their neighbour or when they’re chatting with someone at school, there’s that feeling of, ‘Okay, I trust that this is not because the person has an interest in getting money from me or having me pay them,’ ” she said. 

“It makes a difference to energy system behaviours, a huge difference that is really undervalued and under-recognized when people are thinking about balancing massive systems.”

B.C. does offer rebates on solar panels and battery storage, but Mommsen wants to see the province do more to encourage community-owned energy projects, especially solar. In his opinion, provincial policymakers remain too focused on maintaining B.C.’s highly centralized electricity system when the future demands a distributed grid.

“The future of any grid under climate change has to be distributed,” Mommsen said. “What we need is a distributed system that is resilient under climate change and that helps the community. It empowers the communities and also it will help them understand energy.”

Despite the success of Bear Mountain Wind Farm, Peace Energy Cooperative executive director Don Pettit thinks B.C.’s energy policymakers have yet to fully realize the role co-ops could play in the energy sector.

Boucher agrees. He also sees the current economic moment as an opportunity for co-ops as politicians look to boost homegrown businesses that pay dividends in their communities.

“Done well, this is a very powerful local economic development strategy and boy oh boy, does the timing seem right for local economic development in this country,” he said. 

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.