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.

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. 

“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.’”

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.

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 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.

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.

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.

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.

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.

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.

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

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

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

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

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

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

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

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

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

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

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

What are the big challenges?

And yet, the barriers appear immense.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

There are other challenges.

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

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

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

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

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

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

What would facilitate off-shore wind?

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

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

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

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

“Offshore wind is no different from that.”

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

Summary

• The Ontario government intended to move radioactive waste from the shore of Lake Nipissing to a former mine site outside Sudbury, Ont.
• A lack of consultation around the new location led to strong local opposition, and delayed the remediation project conducted by Nipissing First Nation.
• The waste has now been moved to a disposal site outside Sarnia, Ont., and Aamjiwnaang First Nation, where emissions from the industrial area known as Chemical Valley have affected local air quality.

For decades, radioactive waste sat near the shore of Lake Nipissing. It looked like an innocuous pile of gravel in what was otherwise a stretch of forest. People began using it to backfill lots, fill spaces under decks and build fire pits. In the 1970s and ’80s, Nipissing First Nation began using it to build roads. 

It wasn’t normal gravel, though. It was mine tailings, containing the metal niobium, left there when the Nova Beaucage mine shuttered in 1956 after just seven months of operation. 

“The company just walked away and left it with no remediation at all,” Geneviève Couchie, business operations manager at Nipissing First Nation, said. Couchie led a project to clean up the tailings, which first started in 2019. After being interrupted by COVID-19 shutdowns, the remediation resumed in spring 2024 and lasted almost two years.

In the meantime, Couchie told The Narwhal, she fielded concerns about groundwater and lake contamination from residents living close to the site or to a nearby property owned by Ontario’s Ministry of Transportation that also stored the low-level radioactive tailings. Couchie said she struggled to get satisfactory answers from government agencies.

“The workers wore hazmat suits, and I remember saying from the beginning, ‘How can I tell people they have nothing to worry about when these guys are in full on suits?’ They’re literally 20 feet from someone’s window,” Couchie said. The majority of the workers remediating the site were from the nation, and dressed in protective gear so as not to carry radioactive dust home on their clothes. 

The plan was to load the waste into trucks to be transported to a tailings management area at Agnew Lake, in Sudbury District. It is the decommissioned site of a former mine, near the Township of Nairn and Hyman, and about 150 kilometres from Nipissing First Nation. The nation first had to excavate nearly 50,000 metric tonnes of the radioactive material — enough to build the Statue of Liberty, twice.

But the project faced another unexpected delay. The province had attempted to relocate the waste without consulting the Nairn community, sparking public outcry. Locals organized public meetings to raise awareness and ultimately stop the transfer. 

Eventually, in July 2025 — after nearly a year of advocacy in Nairn, and delay for Nipissing First Nation — the province capitulated, finding another place for the waste to go. This was welcome news for Nipissing First Nation, which is now hoping to transform the scarred land into a lakeside green space for the community to enjoy after years of worry.

“We just wanted to see this material moved off [Nipissing First Nation] lands, and so it was an unexpected disappointment that things were delayed like they were,” Couchie said. “We were pleased that they did end up finding another disposal site.”

“But,” Couchie said, it was “eye opening as well, that there was only one other facility in Ontario that was prepared to accept this.”

That facility is close to another Indigenous community — Aamjiwnaang First Nation, in the Sarnia region, where emissions from refineries and petrochemical plants have earned the area the moniker “Chemical Valley.” 

Sarnia facility accepting radioactive waste from Nipissing

The new destination for the radioactive tailings is Clean Harbors, a hazardous waste facility in Corunna, Ont. — 645 kilometres from its original dumping ground. It’s close to both Aamjiwnaang and Sarnia, which have experienced persistent air quality issues related to nearby industry.

Clean Harbors is the only government-licensed hazardous waste management complex in Ontario, and is “uniquely positioned,” its website reads, to offer safe disposal of naturally occurring radioactive material like the niobium tailings. 

But the facility’s history is dotted with dust-ups over environmental safety. In 2013, neighbours of the Clean Harbors site won a civil lawsuit over the impact of the waste facility’s emissions on their health and daily lives.

In 2019 the company was fined $100,000 for discharging contaminated smoke after a filter cloth soaked with coolant, oils and metal particles caught fire.

When the province conducted a study on environmental stressors in the Sarnia area in 2023, it found that while the majority of the 870 reports from residents about industrial pollution were related to petrochemical industries and refineries, a significant minority — 219 — were “related to the waste incineration facility in the area (Clean Harbors).”

And in 2025, the Ministry of Environment fined Clean Harbors $100,000 for failing to comply with an equipment requirement for monitoring the excavation of a waste-holding basin. 

Clean Harbors did not respond to The Narwhal’s questions about these claims and findings.

In a section of their 2025 annual report on legal, environmental and regulatory compliance risks, Clean Harbors asserted: “We are now, and may in the future be, a defendant in lawsuits brought by parties alleging environmental damage, personal injury and/or property damage, which may result in our payment of significant amounts.”

Aamjiwnaang First Nation Chief Janelle Nahmabin told The Narwhal she had not received any information about the niobium waste that was trucked to Clean Harbors nearly a year ago. Other environmental groups The Narwhal reached out to, including Climate Action Sarnia-Lambton, had not heard of this waste transfer, either.

“The plan now has been executed in a very different way,” said Brennain Lloyd, project coordinator at Northwatch, a northeastern Ontario environmental advocacy group. “It’s moving the waste into the territory of another First Nation that is already heavily impacted by all of the industrial activities.”

‘Under a real nuclear shadow’: radioactive waste in northern Ontario

The company behind the Nova Beaucage mine was looking for much-desired uranium in the early days of the Cold War. 

It found trace amounts of it on a small island in Lake Nipissing, along with niobium, a naturally occurring mineral used to strengthen and lighten steel, which is useful when building electronics, cars, bridges and pipelines. After excavating, the company barged the ore across the lake to a mill they established on shore, on Nipissing First Nation territory.

“In northeastern Ontario, we live under a real nuclear shadow,” Lloyd said.

In a letter to the federal Impact Assessment Agency in February 2026, the Anishinabek Nation cited the Nova Beaucage tailings as an example of the legacy of contamination that First Nations have been disproportionately impacted by due to poor government diligence. The letter puts the “toxic cocktail from Sarnia chemical valley” near Aamjiwnaang First Nation in the same category.

It was written in response to the proposal by the federally mandated Nuclear Waste Management Organization to store radioactive waste from nuclear power plants outside Ignace, Ont., a northern township between Thunder Bay and the Manitoba border. This waste has been temporarily stored in safe, but impermanent, containers for decades and finding a permanent solution has become an increasingly pressing issue — one that has only grown as Ontario ramps up nuclear power generation with small modular reactors in Bowmanville and a proposed full-scale nuclear facility in Port Hope. 

From First Nations in the Ignace area to those along the Ottawa River, concerned by leaks from a nuclear laboratory in 2024, communities have been pressing for better consultation when big radioactive waste decisions are made. The case of the Township of Nairn and Hyman illustrates why.

In June 2024, a Nairn and Hyman town councillor happened upon the planned dumping site for the niobium waste while out riding an all-terrain vehicle, or ATV, said Belinda Ketchabaw, the chief administrative officer of the township of less than 500 people. According to the township’s website, the councillor saw roadwork being done to facilitate the transportation of material the Ministry of Mines later told residents was naturally occurring radioactive material. Before that, residents say they had no idea about the relocation plan.

“We were aware that [the Agnew Lake] site was within our township. It’s been there for many, many years,” Ketchabaw told The Narwhal. “What we weren’t aware of is that the cover over the existing tailing site had depleted, through either people going across it on ATVs, or just rainwater eroding the cover.”

The Agnew Lake site already needed remediation, after uranium mining and milling operations ceased there in 1983. Tests from 2023 by the Ministry of Mines found uranium, radium, arsenic and more at the site. In a letter sent to the federal nuclear safety commission in the months after the councillor’s discovery, the township argued the arrival of niobium waste introduced “additional risks to an already precarious situation.” 

The province’s idea, according to an undated letter from the Ministry of Transportation, was for the niobium gravel to help provide an additional, less radioactive groundcover for the existing materials.

“I guess what they were trying to do is, for lack of a better word, kill two birds with one stone,” Ketchabaw said. She made it her personal mission to get answers about the waste disposal that she said were not provided by the province — although the Transportation Ministry letter, uploaded to the Nipissing First Nation website, says the site was identified by the Ministry of Mines as a potential disposal location in 2016. This same letter explained that studies done by the ministry in 2012 determined the potential “risks of the tailings to human health were low.”

Ontario’s Ministry of Energy and Mines did not respond to The Narwhal’s questions, including around its protocol for informing communities about plans to store radioactive waste nearby.

“Ministries that are doing this type of work have to have advanced and meaningful consultation with municipalities, First Nations and residents,” Ketchabaw said. Agnew Lake is a source of drinking water for the Nairn and Hyman communities. She said they were given no assurances the environment and health of the community would be protected with this disposal.

“We weren’t consulted at all in this project. We came upon it by mistake,” Ketchabaw said. “It really felt like they were hiding this, like they were just kind of trying to sneak it in the back door.”

Updated on May 6, 2026, at 12:10 p.m. ET: This story has been updated to correct a photo caption that stated nearly 50,000 metric tonnes of material were removed from the picture site, when in fact that collective amount was removed from multiple sites across the nation.

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After years of punishing drought that shrunk their herds, Canadian cattle farmers finally saw them growing at the start of 2026. It was a modest 2.5 per cent increase in the number of cows and calves, but after eight years of contraction — which also meant increased beef prices at the till — those in the industry are taking it as a win. 

Brenna Grant, executive director of CanFax, the research division of the Canadian Cattle Association, called this a “really modest” increase, urging patience for those hoping affordability will return soon. 

Canada’s beef prices are 23 per cent higher today than the national five-year average, and, in general, meat prices rose by the highest rate of any food category in 2025, according to research from Dalhousie University. 

The biggest concern driving beef prices high is weather, Grant said. Climate pressures on pasture conditions means less hay to feed animals and, consequently, smaller herds.

“All of the research would indicate that we are expected to see greater frequency and severity of extreme weather events, whether that be drought or flooding or even just greater volatility within the growing season,” Grant said. 

Ranchers are heading into summer with mounting uncertainty, given spotty and unpredictable rain and snow patterns in recent years. “That just means that this rebuild, in terms of increasing supplies, is going to take longer.”

Droughts in Alberta, Saskatchewan and Manitoba, where the country’s cattle farming is concentrated, have become regular and severe. Drought insurance payouts to Alberta farmers reached a record $326.5 million in 2023, more than tripling the payouts from the 2021 drought. 

Droughts also hit southern Ontario last summer, impacting Trenton, Belleville and Prince Edward Country farmers. Dry conditions present a host of challenges, from reducing the availability of local, affordable feed to farmers not having enough water available for their herds. 

At the same time, more northern areas of Canada that haven’t historically been seen as cattle country are starting to grow their local bovine populations, as more moderate temperatures become a welcome refuge for farmers. Warmer weather has been a boon in typically colder zones, making it easier to grow feed crops instead of importing them. 

Northern Ontario is one of those areas, including Sudbury, Nipissing and Cochrane, which had built up a herd 100,000 strong as of 2018. 

Grant said the Peace Region that straddles the Alberta-B.C. border is also seeing longer growing seasons, allowing for more crop varieties, including of animal feed. The same is true for northeast Saskatchewan, once considered too cold and wet, where warmer, drier conditions have improved growing.

“It’s the right use of that land for the right product,” said Jason Leblond, president of Beef Farmers of Ontario, and a cattle farmer himself in Chisholm, Ont. “Beef cattle do very well in the north.”

But, he says, while the shift may benefit local producers, it is unlikely to ease rising beef prices anytime soon.

“When we see the first signs of the herd rebuild, which is what we’re seeing currently, it normally takes two years for it to hit the store shelves — that price reduction,” Leblond said.

Building up northern herds, he said, is a big part of “how we can get the prices more in check.” He’s increasingly seeing farmers step up in these long-dormant farming regions.

Northern Ontario’s growing herd of cattle

In the early 2000s and 2010s, cattle farmer Mike Tulloch recalls driving roads in Algoma, Ont., and seeing derelict farms, growing back up to brush and weeds — signs of a dying industry. Tulloch grew up in the area with a lifelong ambition to take over his father’s farm and watched the landscape closely.

In the last decade, he’s seen a growing number of farmers revitalizing the area’s farms, many coming from southern Ontario or farther. His own land, he said, doubled in value since he bought it in 2018. Now, he owns a farm with about 1,300 head of cattle. 

“The face of agriculture in Algoma and Manitoulin has changed dramatically,” Tulloch said. “It’s driven out of the relatively inexpensive value of the land and is being bought up hand over fist and turned back into productive farmland.”

Tulloch has found himself in one of the most hospitable remaining areas for raising cows.

“No question that the climate change has been more conducive to farming in the near-north: Algoma, Manitou and Sudbury, Nipissing,” Tulloch said. “This is a case where climate change in our area has been good for the farmers.”

The Algoma area, at the cusp of lakes Huron and Superior, has the longest growing period across all of northern Ontario, from Nipissing up. By 2050, temperatures are predicted to increase between 1 C and 4 C, making that growing season even longer. 

“We have warmer winters. We get on the land sooner, and the ground in the north here warms up sooner,” Tulloch said, compared to previous years. “For our cattle operations, we grow about 750 acres of corn. And, ten years ago, there wasn’t 750 acres of corn in the whole district.”

While many Canadian cattle farmers are battling extreme weather events like drought, floods and wildfires, northern Ontario is emerging as somewhat of a sanctuary. 

Moving north won’t fix the challenges climate change presents farmers

Experts and polls have demonstrated the biggest challenge for cattle farming in Canada is the increased frequency of adverse weather events. While the northerly migration has eased the challenges for some cattle farmers, it’s not a silver bullet — and prices will continue to reflect that, especially as consumer demand for protein remains extremely high.

“In the last five years, we’ve actually seen beef demand jump twice, once in 2020 and we maintained those levels, and then again in 2025,” Grant said. “What that means is that consumers were willing to pay a higher price for the same amount of beef.”

The high demand and weather uncertainties are being experienced across the world, including in Canada and the U.S., leading to a global shortage of beef as production falls in traditional centres.

There are also no guarantees conditions will remain hospitable for cattle farming in northern climates. 

“In some regions of the country, certainly, there will be some increased opportunity,” Kim Ominski, University of Manitoba research scientist, said. “But the challenge about these extreme weather events is it just introduces increased risk.”

Unpredictable growing conditions might bring a year where farmers are unable to source enough feed locally. Since feed is one of the largest costs of raising cattle, Ominski said, having to import it — especially if that requires swapping the usual meal with a more expensive crop — can really impact a farmer’s bottom line. 

Across Canada, research links extreme climate-driven weather events to rising mental-health strain on farmers, causing guilt, hopelessness and panic. Many are leaving the industry.

Even Tulloch acknowledges the gamble.

“The weather is more erratic,” Tulloch said. “You see that when the storms come, there are heavier storms and you have more risk of flooding.”

“It’s a risky venture.”

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Summary

• In 2024, an extreme cold event caused many B.C. wineries to lose most of their grapes. In response, the province allowed wineries to join a program allowing the import of U.S. grapes, a practice usually reserved for larger commercial labels. 
• The full rules about how sales of wine made with U.S. grapes would be taxed were released months after wineries had already bought foreign fruit. Each winery got a sales tax exemption on a specific quantity of wine — after that, taxes could reach as high as 89 per cent. 
• These taxes apply to all sales for as long as wineries sell any wine made with U.S. fruit, even if the actual bottle in question is made with 100 per cent B.C. grapes. The result, winemakers say, is losing out on years of profits and, possibly, going out of business.

The program offered a lifeline when the forecast was unequivocally dire. In January 2024, temperatures dropped below -25 C in B.C.’s Okanagan, Thompson and Similkameen Valleys — the province’s agricultural breadbasket. 

The cold snap in the Interior came right after unseasonable daytime highs of 10 to 13 C. The weather whiplash hit the area’s fruit trees hardest: acres of peaches, pears, plums, apples and nectarines were damaged, with the plants’ buds dead come spring. The ripe, juicy produce tourists flock to the Okanagan for in summer and fall never arrived.

The deep freeze also crushed one of B.C.’s most prized commodities: wine grapes. More than 90 per cent of the Interior’s annual harvest was lost, which meant nearly 90 per cent of the province’s total vineyard acreage. Suddenly, a $3.75-billion industry was in crisis. 

“There were zero grapes,” Paul Sawler, vice-president and general manager of Dirty Laundry Winery, a mid-sized winery in Summerland, B.C., recalls. The winery’s 100 acres of vineyards produced almost no fruit.

“Where we would normally see 300 to 400 tonnes [of grapes], we got less than half a tonne from all the vineyards combined,” Sawler says.

The solution seemed clear at the time: “There was no way to survive except to buy Washington State grapes.” 

In British Columbia, alcohol is regulated by the BC Liquor Distribution Branch, a government body long assigned to the Ministry of Public Safety and Solicitor General. In July 2025, it was transferred to the Ministry of Agriculture and Food — a nod to the realities of producing a weather-dependent consumer good in an increasingly volatile 21st-century climate. For winemakers and grape growers, who had seen several difficult years of damage to their vineyards from extreme weather, it was a welcome move.

Under the liquor branch’s policy, certain wineries — mostly larger operations that hold a commercial winery designation — are allowed to import foreign grapes to complement their B.C. fruit. Often acquired from the U.S., these grapes produce wines that the liquor branch taxes at high sales mark-ups — the dollar amount the branch charges a winery when it sells its wines directly to consumers, restaurants or other distributors.

Regulations normally prevent most small and mid-sized B.C. wineries from purchasing foreign grapes. This is part of the liquor branch’s complex policy, which involves different regulatory and taxation systems not just for different types of wineries, but also for direct-to-consumer sales versus sales through the liquor branch. The short version is that independent, “land-based” wineries are required to use exclusively B.C. fruit, in exchange for which a good chunk of their sales are tax-exempt. 

After the 2024 freeze, the liquor branch relaxed these rules, allowing a wider range of wineries to import grapes to salvage their businesses. But bringing in foreign grapes meant signing on to a program that limited each winery’s tax-exempt sales. 

“We really had no choice,” Sawler says of his decision at Dirty Laundry. Though most Okanagan wineries were committed to making B.C. wines with B.C.-grown grapes, the weather had decided for them. 

“If we didn’t buy the grapes, we would have had to lay off half our staff,” Sawler says. “We probably would have had wine to sell at the winery, but we would have lost our whole outside market — a market that we spent the last 20 years building.”

So, Dirty Laundry and 91 other wineries in the area rolled the dice and brought in foreign grapes to make their 2024 wines. 

“I don’t regret buying them,” Sawler reflects. “The quality was good; the pricing was good. It worked out well.” 

But the decision has come with a latent — and significant — unanticipated cost. The limit on wineries’ tax-exempt sales was based on a complicated calculation many did not understand at the outset. In fact, some didn’t understand they’d be subject to mark-ups at all. Now that the program is in its second year, some wineries have wine they can’t sell without a significant financial hit.

“A program that was basically designed to help wineries, in some cases may actually kill some wineries,” Sawler tells The Narwhal. “Those are extreme cases … but it is happening”

“We know how devastating the 2024 freeze event was for grape growers and wineries in the Okanagan and we’ve worked together with the B.C. wine industry to help them recover,” Minister of Food and Agriculture Lana Popham told The Narwhal in an emailed statement. 

“The Liquor Distribution Branch will continue to work closely with wineries and Wine Growers BC.”

A program that brought wine flowing back into B.C. has soured

The vintage replacement program, or just “the program,” as many in the industry refer to it, was first announced in July 2024 and laid out in fine print in a liquor branch memorandum that October. Importantly, this was after most wineries had already purchased U.S. and foreign grapes. 

For the 2024 vintage, the BC Liquor Distribution Branch would permit wineries that opted in to the program to purchase foreign grapes or a partially fermented product known as unfinished juice, and would treat any wine produced from those products the same as B.C.-grape wine. That meant the liquor branch would offer the tax exemption usually reserved for certain types of 100 per cent B.C. wine to all B.C. wineries using foreign grapes.

This main component of the program was a success. Wineries like Dirty Laundry and many smaller, newer wineries kept their staff, juiced their grapes and made wines they were proud of. The wider industry, which supports a substantial economy of restaurants, hotels, hospitality workers, supply companies, migrant agricultural workers and small family businesses remained afloat.

But the details were a shock to many.

The exemption wasn’t a blanket exemption. Each winery had what was known as a “support cap,” or a limit on tax-free exemptions. Wineries’ individual caps were based on an “Olympic average” of five years of previous mark-up exemption totals — for land-based wineries, of their B.C.-grape wines; for commercial wineries, of B.C.-grape wines certified by the BC Wine Authority’s Vintner’s Quality Alliance, or BCVQA. This was a dollar value calculated by taking the mark-up exemption on sales numbers from the past five years, dropping the highest and lowest numbers, and averaging the three remaining years. 

Sales over that limit were taxed at the liquor branch’s standard rates for foreign-grape wines — as high as 89 per cent on the first $11.75 of the wine’s per-litre value, and 27 per cent after that. 

The calculation didn’t pose a problem for many commercial wineries used to importing foreign grapes — and selling huge volumes. It was also doable for many established wineries that had relatively steady sales over the period in question and dedicated accounting departments. It did pose an issue for many newer, growing independent wineries, though. 

Another surprise was how long a program meant to help with one bad year was going to last. The ability for wineries to buy foreign grapes for tax-exempt wine was extended for the 2025 vintage, to account for any lingering cold snap effects on the province’s vineyards. Additionally, once participating wineries brought in foreign grapes, they were tied to the vintage replacement program until they’d sold every last bottle of wine containing U.S. grapes.

This all means the support cap will remain in effect until March 2028, to account for the added year of foreign grapes, and sales of wines that take longer to produce, like reds or sparklings. 

All that, and the mark-up exemption limit each participating winery received was not exclusive to its U.S.-grape wines. Post-limit taxes would be applied to all the wine a participating winery sold. 

Let’s say a winery had 5,000 cases of U.S.-grape wine — “replacement” wine — left to sell, starting this year. That newer stuff would likely share shelf space with bottles of carefully cellared, 100 per cent B.C.-grape wine from years past, too. Signing onto the program meant this B.C.-grape wine would count toward the winery’s annual mark-up exemption limit. Which means that once the winery hit the annual limit set by its Olympic average, this 100 per cent B.C.-grown-and-produced wine would be taxed the same way as malbec from Argentina: at up to 89 per cent. 

In an emailed statement on behalf of the liquor branch, the Ministry of Agriculture said that “to ensure revenue neutrality and fairness across the sector, the annual support cap … includes all wines sold within the fiscal year, including vintage replacement wines, BCVQA and 100 per cent B.C. grape wines.” 

The ministry added that a support cap based on historical sales data was recommended by Wine Growers BC.

“From the outset, there were very clear guidelines communicated to the wine industry about eligibility and annual support caps, and it was intended to help the industry keep the lights on during a very serious agricultural emergency,” Minister Popham told The Narwhal.

“It is in everyone’s interest to return to producing 100 per cent B.C. wine production.,” the liquor branch-attributed statement concluded.

Small, new B.C. wineries suffering the most under program’s limits

Paul Sawler’s neighbour in Summerland, Ron Kubek, started Lightning Rock, a small, family-owned business just up the road from Dirty Laundry, in 2017. It’s grown steadily ever since. 

“I think the problem in the wine business is that too many people in ownership or in the tasting room want to show how smart they are,” he says. His greatest pride is his winery’s consistent five-star ratings on Google, which show that everyday people appreciate Lightning Rock’s approach.

“Wine is supposed to be something that’s enjoyed among friends and family. Some of my favourite reviews are, ‘It was my first time in the tasting room and they didn’t make me feel dumb.’ We can talk about the technical stuff, but we’d rather just have fun.”

Kubek hasn’t shied away from sharing his views on the program, which his winery also opted into after losing its 2024 harvest. 

“We’re still small, but we’ve experienced tremendous growth, from just a few bottles in 2018 and 2019 to [when] the pandemic hit and wine sales went through the roof,” he tells The Narwhal. 

But that initially promising upward trajectory is now proving an impetus to further growth. The program calculated Lightning Rock’s mark-up limit using the low sales volumes of its early years, and now the winery isn’t eligible to sell much tax-exempt wine.

Kubek says his situation is “not because we brought in too many grapes from the U.S. — we brought in about 60 per cent of what we would normally do in a year after the catastrophic [harvest] loss — but because … [the liquor distribution branch] took what was a simple program and misapplied the Olympic average to help jack up revenues and get their bonuses.” 

Lightning Rock’s speciality is single-varietal wines, a large portion of which are reds and sparklings that take several years to age. That means Kubek will likely have to remain in the program until 2028. As a result, he has to carefully calculate the amount of wines from previous B.C. vintages he can sell each year without losing too much profit.

“The problem is that my previously B.C. [tax-]exempt wines are now being taxed or in danger of being taxed,” he says. “So I’m trying to grow, but I have a limitation, because if I do grow, I’m suddenly hit with an 89 per cent tax.” 

So Kubek, like many Okanagan winery owners, was holding back sales in March when he spoke with The Narwhal — waiting anxiously for the liquor branch’s fiscal-year turnover of April 1 to reset his mark-up limit. For a small winery with hard-won personal relationships with restaurants and other distributors, the cost is significant. 

“I’m having to tell my sales agents, ‘Hey slow down on sales,’ because I’m very, very close to going over my Olympic average and then suddenly I’m going to be paying 89 per cent tax on a bottle of wine.”

Kubek says he would have been able to sell an additional 1,000 cases of wine in the last fiscal year if it weren’t for his mark-up cap.

In response to The Narwhal’s questions about these limitations, the agriculture ministry noted, “While some wineries accessing the temporary supports have exceeded their annual cap and are facing payment obligations, many other wineries planned their operations around the annual support cap or chose not to access the temporary supports. Any changes to the policy directives or requirements mid-stream would not be fair to these businesses.”

Kubek feels frustrated. “I lost all my fruit. I had to pay for fruit to come in and now the government’s penalizing me if I try to grow.” 

He believes the program has hurt wineries like his the most. 

The support cap clause in the vintage replacement program was meant to prevent some of the Okanagan’s biggest wineries from bringing in more cheap foreign grapes than they normally would while paying below-normal sales taxes, Kubek says. It was supposed to prevent these grapes from flooding the B.C. market, which could have changed the industry’s local fingerprint and provided an unfair advantage to some. 

But what the government feared never happened, and the little guys are the ones now being hurt, Kubek says. He pointed to two wineries under the same ownership — Kelowna’s Mt. Boucherie Estate winery and Rust Wine Co., a smaller winery in Oliver — which confirmed they have had to lay staff off as a result of tax bills currently exceeding $500,000.

The agriculture ministry told The Narwhal, “In recognition of the payment obligations for those that exceeded their cap last fiscal, the [BC Liquor Distribution Branch] will continue to work with wineries to explore flexible payment arrangements within reasonable timelines.”

B.C. wine industry is pushing for solutions to a complex situation

Jeff Guignard is the CEO of Wine Growers BC, the primary industry marketing and lobbying organization for B.C. wines. He has heard his fair share of complaints about the vintage replacement program, including from Kubek, who he speaks to nearly daily. He also speaks with the provincial government every week, trying to find a solution for wineries who say the taxation approach has pushed them to the financial brink.

“This program was an essential lifeline to industry in a moment of generational crisis,” Guignard says. “It literally saved people’s businesses. There are wineries in B.C. that would not be in operation without this program. So we’re immensely grateful to government for that.” 

But, he adds, “It’s now clear — because things were rushed, and though everyone was doing their best — that the program has had some unintended consequences.” 

Guignard says the constraints built into the program for good reason are now injuring the very people and businesses the program was designed to support. 

“The constraint is acting as a limit on sales,” he says. “You could be selling, right now, a 100 per cent made-and-bottled-and-grown-in-B.C. wine, that was bottled years ago, prior to the freeze, and prior to the program being developed. But it counts against your business as though it were part of the program.” 

Guignard says the problem with the program is its one-size-fits-all approach, when the province’s wine industry ranges from huge, established players like Arterra Wines Canada or Andrew Peller Ltd., which both own multiple wineries, to medium-sized operations like Dirty Laundry and smaller newcomers like Lightning Rock. 

He says he knows of over a dozen wineries that have gone over their support cap and received invoices from the provincial government — businesses being treated “as though they were importing foreign wine into the province.”

“The program was designed to help you not have to do that,” he says, adding that one person told him, “ ‘I wish I hadn’t brought any fruit in. I would have had no wine, and I would have had to lay off all my staff, but my business would actually be in a better place, financially.’ ”

Adding to the challenge is the fact that the 2025 grape harvest in the Okanagan and Similkameen was — to everyone’s surprise — highly productive. Many of the vines that had survived the cold freeze produced abundant fruit, but grape growers unattached to specific wineries were left without customers. Businesses trapped in the “golden handcuffs” of the program, as Guignard terms it, weren’t buying, because they weren’t looking to make new wines they couldn’t turn a profit on. 

With growers, too, facing financial hardship, the program has in some ways simply deferred the crisis it was trying to prevent. The crucial support the program offered when the industry seemed on the brink of collapse has turned into an albatross hanging over some winemakers’ necks. 

“From a Dirty Laundry perspective, I’ve taken the position that if I had 1,000 cases of imported wine left over at the end of March next year, I’d dump it before I’d stay in the program another year,” Sawler says. “That’s the amount of impact it’ll make on our winery. We’d be better off to throw the wine away or to sell it for nothing … to make it go away.”

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Summary

• Farmers in Saskatchewan are dealing with variable weather, exacerbated by climate change. For many, this has meant hotter, drier summers, but the experience is far from universal.
• In some areas of Saskatchewan, growing conditions have improved with a changing climate.
• Farmers are also better equipped to deal with harsh weather, as new technologies and farming practices develop.

Scott Hepworth’s great-grandma used to have to shovel dirt out of the kitchen after dust storms swept across the Prairies.

More than a century later, drought is still a factor on Hepworth’s fifth-generation family farm near Assiniboia, Sask. In fact, it remains a defining feature of the land, which sits within the Palliser Triangle, one of Canada’s driest agricultural regions. 

But despite increasingly volatile weather in recent years, including long dry spells, record heat and sharp swings between extended drought punctuated by patchy rain, Hepworth says his crops aren’t suffering — instead, they’re performing better than expected in these conditions. 

He estimates that since he began farming in 2004, his crop yields during hot, dry summers have roughly doubled compared to what they were a few decades ago. 

It’s come as a surprise to some farmers across the Prairies: they are seeing the impacts of climate change, yes. But those impacts haven’t necessarily been bad for their bottom lines.

Only a few hours away from Hepworth’s farm, in northeast Saskatchewan — a region once considered too cold and wet — warming temperatures and drier conditions have improved growing conditions. 

“We were the worst place in the province to farm when I started farming, and now we’re the best place,” Ted Cawkwell, who owns a farm in the area with a couple partners, says.

On his land, fields that were historically difficult to seed and harvest are now more reliable. And he hasn’t seen damaging early frosts, once common every few years, in decades. 

Cawkwell says yields on his farm have improved dramatically over the past decade. The area overall has seen some of the highest yields in the province in recent years.

While there are several reasons for this — including better crop genetics and farming practices — Cawkwell believes changing weather patterns have been a major factor, too. 

“Twenty years ago, I would have never guessed the climate could change like this. You think of climate change as in tens of thousands, or millions, of years — not twenty. And that’s kind of the scary part of this.”

Farming wins are a combination of changing weather and new practices

Of course, the story is nuanced. On Hepworth’s farm, it’s not just the changing climate that has improved his crops. Conserving moisture has long been a focus for the family. Hepworth’s dad adopted what’s known as minimal-till seeding in the 1980s — essentially, reducing or eliminating the need to plough the soil when planting new seeds. This has improved soil health and reduced erosion. Another practice that Hepworth believes has benefited his farm is called continuous cropping, meaning every acre has a crop on it every year; roots in the ground rather than bare fields help retain moisture and protect the soil.

Advances in crop genetics have also played a big role, Hepworth says. He also serves as a director for SaskWheat, the Saskatchewan Wheat Development Commission — a farmer-funded organization that invests in wheat research and crop variety development. Over the past several decades, hundreds of millions of dollars in public and farmer funding have gone into developing new wheat and durum varieties in Canada. Hepworth is now able to grow drought-tolerant wheat and durum varieties bred to be shorter and better able to withstand stress.

It’s all helped. Hepworth, now in his early 40s, has his own memories from his childhood, of dust storms so intense he couldn’t see across the yard. Largely because of improved farming practices and soil management, he hasn’t seen one since. 

For Hepworth, a combination of climate, farming methods and technology have led to increased success.

But the experience is anything but universal.

“It’s been quite variable, even within a few kilometres,” he says. 

In parts of southern Saskatchewan, particularly deeper into the Palliser Triangle, recent conditions have had a very different impact.

A few hours southwest of Hepworth’s farm is Climax, Sask. — one of the driest regions in the province. 

Here, farmer Cody Glenn says he has experienced about six consecutive years of drought on his farm. 

In 2021, the worst year for drought in Saskatchewan in two decades, Glenn says 260 acres of barley resulted in almost nothing. The crop couldn’t even be properly harvested, producing just a couple bales of low-quality feed.

In other recent years, his barley yields were around a quarter of what they should be. 

In light of all this, he says his current strategy is just to stay viable. 

Despite changing weather, crop yields overall are holding — and even rising across the province

Even though there’s no question some farmers have struggled under increasingly variable weather across the Prairies, crop production has not declined as sharply as some predicted. 

The reality is far more nuanced, Dave Sauchyn, a leading Canadian climate scientist with a focus on the Prairies, says. 

“There’s no single climate,” he says. “It varies a lot from place to place.” 

Across the Prairies, climate change is showing up most clearly through warmer winters and longer frost-free seasons, rather than consistent increases in extreme summer heat, he says. 

In many areas, peak temperatures still haven’t exceeded those seen in the 1930s, in the “Dust Bowl” era.

Water patterns, however, are shifting in more complex ways, he adds. Snow is generally melting earlier, more precipitation is falling as rain instead of snow and less water is available later in the summer. 

As a result, Sauchyn says, drought remains the main concern. That pressure is most acute in the Palliser Triangle, where dryness has long shaped farming practices. But in recent years, moisture stress has also become more common in parts of the northern and eastern grain belt — areas that historically faced fewer drought constraints.

And not all these changing patterns are bad for farming regions. 

Fewer and shorter cold periods are extending the growing season. In some regions — particularly along the northern and western margins of Saskatchewan — this is actually improving production, as Cawkwell has seen on his farm.

And despite increased variability, overall crop performance has remained relatively strong. Yields for major Saskatchewan crops such as wheat and canola have generally trended upward over the last couple decades, with many recent years coming in at, or above, long-term averages. 

Jeff Schoenau, a soil scientist at the University of Saskatchewan, says this reflects decades of improvements in farming practices.

He says comparisons of Prairie soil samples from 1996 to 2018 show significant gains in key indicators such as microbial biomass, respiration and organic matter — factors that contribute to healthier, more resilient soils. These improvements are the result of smarter farming practices, he says. That includes conservation tillage (avoiding or minimally ploughing a field every year), diverse crop rotations (not planting the same monocrop in the same field year after year) and more precise use of fertilizers.  

Combined with advances in crop genetics and other improved farming strategies, Schoenau says crops today can withstand conditions that would have caused far greater losses in the past.

And while climate scientists like Sauchyn expect continued variability — and potentially more severe drought — Schoenau believes farmers will continue to adapt. 

“Farmers are pretty resilient, and when things change, they adapt and they use all of the resources and ingenuity and expertise available.”

Some scientists and farmers are cautiously optimistic — but not all

Sauchyn is also cautiously optimistic. 

He is clear that prolonged drought would pose serious challenges, particularly in a warmer climate. It will be critical, he says, to understand the difference between what’s a short-term blip and what is a long-term trend. 

But his team’s projections, based on large geospatial datasets of climate, soils and yields, suggest that northern and western margins of the grain belt may continue to benefit. That’s because it’s getting warmer and growing seasons are getting longer.

This offers little hope to farmers like Glenn, who lost the lottery in terms of farm placement. 

He says farmers in his area are displaying their despair.

“There’s more land for sale down here than there is buyers.”

For now, he hopes crop insurance will help carry him through, but if dry conditions persist, the path forward becomes less clear — particularly in areas where irrigation options remain limited. 

“I know I’m an optimist. I always have been, but it’s really hard to see the future currently.”

Hepworth is inspired greatly by his great-grandparents, who persisted through their own tough times.

“We’re in a dry cycle now, but farmers always find ways to adapt, and we’re always looking for ways to improve our soil health and leave our land in better shape for the next generation,” he says. 

“I feel as though every generation on this farm has had it better than the last, and that’s what motivates me.”

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.

Early in the afternoon of Oct. 10, 2015, John Ashley Pryce noticed something strange in his yard. A garbage bag was torn open, and trash was “strewn about the property” in Eastgate, B.C., a small community just east of E.C. Manning Provincial Park.

Pryce took in the scene, his eyes passing over yellowing leaves and dried grass before coming to rest on a massive creature sniffing the detritus. Its fur was mottled with shocks of brown, blonde and black. His eyes traced a prominent hump behind its shoulders and a round, dish-shaped face, both hallmark characteristics of a grizzly bear. 

Pryce grabbed his camera. The shutter snapped as he took a photo. The bear looked up at him for a few seconds before tearing off down the hill and disappearing.

Pryce couldn’t have known it at the time, but this would be the last confirmed grizzly sighting recorded in the North Cascades. A range of mountains, glaciers, rivers and forests stretching from Lytton, B.C., to just east of Seattle, Wash., it is one of the wildest transboundary ecosystems anywhere along the Canada-U.S. border. It is also home to one of the most endangered grizzly bear populations on the continent. 

Scientists estimate that, at most, six grizzly bears still live in the North Cascades. It’s not clear how many bears were once there, but according to Hudson’s Bay Company records, some 3,788 grizzly pelts were shipped from forts in the region between 1827 and 1859. Later records from miners, surveyors and settlers make note of dozens of grizzlies killed throughout the region. 

Today, many experts call the North Cascades grizzly an extirpated species, meaning locally extinct. The International Union for Conservation of Nature has “red-listed” the bears, labelling them “critically endangered.”

Since the bears were listed as threatened under the U.S. Endangered Species Act in 1975, efforts have been made on both sides of the border to recover the population. Most recently, in 2024, the U.S. National Park Service and the U.S. Fish and Wildlife Service announced they would begin reintroducing bears into North Cascades National Park — an effort derailed after Trump’s return to office led to funding and staffing cuts for both agencies. 

But an Indigenous-led project called the Joint Nations Grizzly Bear Initiative has continued to move forward. Led by the Okanagan Nation Alliance, the project is a collaboration with First Nations throughout the region, including the S’ólh Téméxw Stewardship Alliance, the Nlaka’pamux Nation Tribal Council, the Lillooet Tribal Council, the Upper Similkameen Indian Band, Simpcw First Nation and the St’át’imc and Sekw’el’was. Together, they’re hoping to begin reintroducing grizzlies to the North Cascades in 2026. 

Cross-border grizzly efforts hindered by false starts and government cuts

The mountaintops in Manning Park were still dusted with snow when Joe Scott arrived in early June 2024. He had travelled from his home in Washington for the first in-person gathering of the Joint Nations Grizzly Bear Initiative. For Scott, the trip was decades in the making. He started working at Conservation Northwest, a transboundary conservation group based in Washington that was then called the Northwest Ecosystems Alliance, in 1998. At the time, he explains, “It was the only group that was advocating for grizzly bear recovery. Nobody else would touch it.”

When the Joint Nations gathering began, it had been only a few months since U.S. agencies announced their reintroduction plan. Grizzly advocates felt that they were closer than ever to bringing bears back to the North Cascades. But Scott had seen recovery efforts fail before. 

In the 1990s, budget constraints forced then-U.S. grizzly bear recovery coordinator Chris Servheen to choose between recovering bears in Montana or in the North Cascades. In what Servheen called a “command decision” he picked Montana, arguing that the Montana project seemed more likely to succeed.British Columbia came close a few years later. In 2001, they were on the verge of moving bears from Wells Gray Provincial Park in the B.C. Interior to Manning Park. But when the BC Liberal Party swept to power, it cut wildlife and conservation programs, prematurely ending that effort. Since then, according to Scott, North Cascades grizzly recovery has been a series of “lurching fits and starts.”

At the June 2024 meeting, conversations among the more than 70 Indigenous leaders, community members, researchers and conservationists connected Western and Indigenous science. Participants spoke about preparing for grizzlies’ return to the landscape, discussed challenges in public education and coexistence strategies. They outlined plans to mitigate human-bear conflict and shared ways to manage garbage and other attractants. 

Matt Manuel, natural resource coordinator for the Lillooet Tribal Council, described it as looking for “solutions within a common habitat that needs to be shared between the grizzly bear and those that are occupying or using the land” in a video produced at the gathering.

Much of the conversation at the Manning Park gathering focused on the North Cascades National Park Grizzly Restoration Plan, which would have relocated three or five bears per year on the American side of the border. At that rate, attendees expected it would take decades to establish a healthy population in the park, and even longer for the bears to move into surrounding lands or up into Canada. Still, the gathering closed with palpable excitement. 

But something nagged at Scott. He was “sitting there on pins and needles with full awareness that the [2024 presidential] election is going to make all the difference in whether this gets done.”

When President Donald Trump was re-elected and unleashed Elon Musk’s Department of Government Efficiency on federal agencies, the worst-case scenario followed: more than a thousand national park rangers, scientists and other staff were laid off in February 2025. Facing an uncertain future, many others resigned. According to the National Parks Conservation Association, the Park Service had lost 24 per cent of its permanent workforce by the summer. The impact on grizzly reintroduction was devastating. 

“Park Service loses staff, Fish and Wildlife loses staff,” Scott explains. “They’re already behind the eight ball with a lack of capacity, and then at this point, they just said, ‘We don’t have the people to do this,’ so it just died.”

The collapse of the plan was a blow, but there was still hope. At the Manning Park gathering, the Joint Nations Grizzly Bear Initiative had not only been preparing for the U.S. plan to bring bears back into North Cascades National Park. They were also developing their own plan, a comprehensive strategy that included habitat conservation, community engagement, public education and, eventually, restoring grizzlies on this side of the border.

First Nations-led effort rooted in Indigenous knowledge of the region

Mackenzie Clarke had never seen a grizzly before she packed up her life and moved from Saskatchewan to the Kootenays to work on a grizzly research project with Garth Mowat, the B.C. government’s large carnivore specialist. Soon, she was hooked. 

Eventually, working on grizzlies brought her to the Joint Nations Grizzly Bear Initiative, where she works as the tmixʷ (wildlife) program lead on the project.

Clarke’s role is unique in wildlife conservation. Rather than a nonprofit or government agency, she works for the Okanagan Nation Alliance, a First Nations government. As someone with settler roots, she thinks it’s an important shift in how wildlife conservation happens. “There wasn’t a lot of Indigenous involvement or consultation” in previous North Cascades grizzly recovery efforts, she explains.

Despite this, Indigenous knowledge has long been key to understanding the history of North Cascades grizzlies. After grizzlies were listed as threatened under the U.S. Endangered Species Act, researchers began looking for at-risk populations. When researchers began studying North Cascades grizzlies, they struggled to find bears. Researchers found evidence of bears, including tracks, scat, digs and bear dens. They set up fur-snagging traps, lengths of barbed wire hung near scented lures and used the gathered fur samples in genetic testing that confirmed the presence of bears. Despite all the evidence of grizzlies, no live bear has ever been captured or collared in the region. 

In the late 1980s, some scientists and politicians argued that researchers’ struggles to capture a bear were evidence against a historic grizzly presence in the North Cascades. So researchers turned to Indigenous knowledge to prove their case. 

“There’s a lot of historical knowledge from the communities on where the bears used to be,” Clarke says. 

Early efforts relied on anthropological research from the first half of the 20th century, which included accounts from Indigenous people of grizzlies near the Chilliwack and Fraser rivers and among high-elevation berry patches. According to late archaeologist William Duff, the Stó:lō knew grizzlies to be “particular frequenters of the high country.”

But by the late 1990s, First Nations were leading their own studies. In 2001, the Stó:lō published a Traditional Knowledge study as part of the B.C. recovery effort. They interviewed more than a dozen community members, recording decades of grizzly bear sightings throughout their territory. 

Both this study and the anthropological records included stories about the unique nature of grizzly bear harvests before settlers arrived in these lands. Grizzlies were not seen as a major food source. They would be eaten if killed, but the nature of the harvest suggested a deeper connection between people and bears. 

Grizzly bear hunters would track the animals while carrying a sharpened bone about the length of their forearm. When they found the grizzly, the hunter would attempt to jam the bone into the bear’s open mouth with the sharp end pointed up. When the bear slammed its mighty jaws, the bone would strike a killing blow into the grizzly’s brain. The stories noted that many grizzly bear hunters ended up one-handed.

In 2014, the Okanagan Nation Alliance’s Chief Executive Council passed a resolution declaring grizzly bears “at-risk and protected within Syilx Territory.” They directed staff to work with scientists and communities to support “immediate action to assist [grizzlies] from disappearing due to low numbers and habitat isolation.”

By 2018, the resolution was starting to bear fruit. They launched field surveys and began writing their own recovery plan. They also started meeting with other First Nations interested in North Cascades grizzlies.

“The governments of all the nations mobilized,” Scott explains, who at the time helped to funnel conservation funding to the efforts. “The intent was to move the recovery process along by identifying the needs and filling the various gaps.” 

That February, the Okanagan Nation Alliance, alongside the Stó:lō, St’ati’mc, Nlaka’pamux and Secwepemc launched a “multi-nation approach for grizzly bear recovery efforts” that would help launch the Joint Nations Grizzly Bear Initiative in 2021. 

Restoring grizzlies benefits the environment — but also cultures and communities 

Jordan Coble was in university when the first pieces that would become the Joint Nations Grizzly Bear Initiative were being put in place. But now, serving as both a councillor with the Westbank First Nation and as the chair of the Okanagan Nation Alliance’s Natural Resource Committee, he’s grateful for “the courage of those that come forward and say, ‘We should do this, and we must do this, and we must do it together.’ ” 

To Coble, the extirpation of grizzly bears from the landscape echoes what happened to Indigenous Peoples. 

“Where we’re at today is rebuilding from 150 years of colonization, of separation and forced removal and isolation from our land itself,” he says. In this context, he sees restoring grizzly bears as a way to restore not just a creature but also landscapes, communities and relationships. 

“Guiding the path forward has been interesting because colonization was quite effective in separating our communities from one another [and] separating our communities from the land itself,” he explains. “Now that we’re turning back to those practices where we’re reminding ourselves that we have interconnections beyond our communities, beyond our nations.”  

This relational approach extends to the natural world as well. For Coble, North Cascades grizzly bear recovery is just one piece of a bigger project. 

“The nation started returning salmon back to the Okanagan, and then saw the success from that built out into forestry and other aspects,” he says. “That interconnection of all those living species, right from salmon to the tops of the mountains where the grizzly bears live, is really important. It’s kind of nice to think about it that way, that we kind of worked our way up into the mountains.”

North Cascades region can sustain grizzlies, expert says

In late July 2025, a little more than a year after the gathering in Manning Park, Michelle McLellan was back in the North Cascades. McLellan, an expert in the relationship between grizzlies and the landscapes where they live, had been at the 2024 meeting. She had also been hired by the Joint Nations team to evaluate North Cascades habitats for potential reintroduction.

Using studies from the Coast Range, which extends from Yukon to the Fraser River, and other regions where researchers had tracked grizzlies with radio collars, she correlated bear movements with habitat factors such as landscape, climate and plant cover, and used the data to build a model of the potential grizzly bear habitat in the North Cascades.

It was a good start, but McLellan “felt it was important to go to the landscape and see what that looks like.” She and a group of researchers, park rangers and conservationists spent the better part of a week ground-truthing the maps. They bushwhacked through overgrown forests, taking note of the horsetail ferns and sedges that bears like to eat in the spring. They climbed into the alpine, looking for whitebark pines with cones that make a calorie-dense grizzly snack. They counted blueberry and huckleberry bushes, snacking on sweet purple huckleberries as they moved through the landscape, considering the locations of roads, campgrounds and other human pressures that could impact bears or bring them into conflict with people. 

“There’s definitely sufficient food to sustain a population there,” McLellan says, though not as high-quality as the grizzly habitat of the Coast Range or the Rocky Mountains. “In general, we did find some good patches that were far from people … the kind of remote valleys you couldn’t just walk into.”

The habitat evaluation was a big step, but it is only one piece of a complex puzzle that reflects the long history of challenges with recovering bears in the North Cascades. 

One of the more notable chapters in that history was the story of a grizzly bear named Winston. In 1992, Winston was captured near Pemberton, B.C. He had already been relocated once but had returned and was getting into trouble with local farmers. 

Winston was released in eastern Manning Park later that year. He travelled south, crossing into the Pasayten Wilderness, Wash., on the eastern edge of the North Cascades. From there, he headed northwest, through Manning Park and into the Chilliwack River Valley, where hunters picked up his trail and chased him north. 

On Dec. 30, 1992, his radio collar pinged near Bridal Falls, B.C., a small community just east of Chilliwack. Researchers lost track of Winston through the winter, but in April they picked up his trail again and headed north along the banks of Harrison Lake. Whether he had swum across the Fraser River or used a bridge is anyone’s guess. 

By that June, he was back in the Lillooet River Valley close to Pemberton. His radio collar fell off sometime that summer, and for a few years, no one knew what happened to Winston. Then, in 1999 bear with similar markings to Winston was captured again in the Pemberton Valley. This time, the bear had been going after chickens on a local farm. It was relocated to the Anderson River Valley near the town of Boston Bar, where it destroyed its radio collar and was never seen again.

It’s still a topic of some debate whether that last bear was truly Winston. And while North Cascades grizzly researchers like to tell this story, they use it mainly to point out the myriad ways bear relocation has improved since then. For one, male grizzlies, which require massive habitat ranges and have strong homing instincts, aren’t typically used for relocation programs meant to recover grizzly populations. Successful programs in other regions have taught scientists that sub-adult females have the highest success rate. They have also learned to source bears from ecosystems with food profiles similar to those of the recovery area and have developed rigorous evaluation criteria to identify the best candidates for relocation. 

It’s also why grizzly bear augmentation is a slow and meticulous process, expected to take decades to restore populations to a level where they might begin to interact with people. 

For McLellan, success might look like moving 20 bears in the next 10 years. 

Coble takes an even longer view of it.“I feel like we’re not going to know until 20 to 50 years down the road if there’s grizzly bears back in the North Cascades in a sustainable manner,” he says. 

Opposition and concern over grizzly reintroduction lingers, but support is widespread.

Still, when McLellan talks about the project in public, she hears a lot of people worried that “all of a sudden, there’ll be grizzly bears all over the landscape.” 

This isn’t a new concern. Scott describes North Cascades grizzly recovery as “a relatively simple body of work that has been made really complex by people who don’t want to see it happen.” 

Opposition to grizzly bear reintroduction has been loudest on the eastern side of the North Cascades, where livestock operations raised concerns about depredation. In 1993, government representatives at a public meeting about reintroduction held in Okanogan, Wash., faced death threats. In 2001, B.C.’s reintroduction efforts faced opposition from cattle ranchers in the Nicola Valley, including one who told the Vancouver Sun he was “hoping this whole friggin’ program will go away.”

Over the years, many of the concerns of those opposed to reintroduction have been addressed by government agencies and conservation groups. Today, opposition to reintroduction is a small minority. According to polling released by the National Parks Conservation Association in 2023, 85 per cent of Washington residents support the reintroduction of grizzly bears in the North Cascades. There isn’t specific polling on the North Cascades in B.C., but a majority of the public regularly supports efforts to protect grizzly bears across the province. 

Still, the Joint Nations project isn’t taking any chances. When reintroduction seemed imminent in 2024, they began ramping up public education, stakeholder engagement and community efforts. 

“We’ve been trying to make sure that nobody’s going to be surprised that bears are going to be coming back to the landscape,” Clarke says. 

She sees education, habitat restoration and conflict management as critical to the long-term viability of the North Cascades grizzly recovery. Building up support for grizzly recovery in communities is also essential.

“It’s okay to take this community by community, but also, step by step,” Coble explains. “Building that awareness, building the understanding that, more than anything, it’s important that the grizzly bears are here.” 

For Clarke, this community work also means increasing the sense of agency that people throughout the region feel about coexisting with bears. She points out that some of this work is already underway in communities where black bears live. But she also points to a range of other ways for communities to get involved, such as conducting community bear-hazard assessments, developing attractant management plans and engaging Indigenous Guardian programs in bear management.They’re also working to spread the word in non-Indigenous communities. Groups like Conservation Northwest and Coast to Cascades, an organization that aims to restore connectivity among bears in the Cascade and Coast mountain ranges, have long been partners. In B.C., the Joint Nations Grizzly Bear Initiative is increasingly working with the Hope Mountain Center for Outdoor Learning, an outdoor education non-profit based in Hope, B.C. that runs a phone line for reporting North Cascades grizzly sightings. 

Clarke admits it’s an ambitious project with many moving parts. But she is also optimistic about recovering bears and about being ready to support both bears and communities once that happens. 

“There’s not really that many bears,” she says, “so you can set things out properly before, and hopefully, have all the resources in place.” 

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

• A shuttered resort in Kananaskis Country could size up and reopen, with plans to build 1,400 parking spots, mountain coasters, minigolf and space for nearly 10,000 visitors a day.
• The location has been designated under Alberta’s All-season Resorts Act, which aims to speed up approvals for tourism projects.
• Experts are concerned the project, the size of a small city, will consume huge amounts of water in a region already dealing with drought.

Hidden amongst the sprawling, rugged network of public land, protected areas and provincial parks 125 kilometres west of Calgary, scattered, partially boarded up buildings sit below mountain peaks. They are the relics of the once-vibrant Fortress Mountain Resort. 

Now the company behind the on-again, off-again ski resort is applying under the All-season Resorts Act to build out its aged resort as a much-expanded four-season destination.

But when Fortress Mountain Resort unveiled its redevelopment plan in January, many were left with more questions than answers, particularly when it comes to the water supply for thousands of visitors to a drought-stricken region. 

“I don’t understand where that water’s going to come from,” Bob Sandford, senior government relations liaison with the United Nations University Institute for Water, Environment and Health, said in an interview with The Narwhal. 

The resort would welcome nearly 10,000 additional daily visitors to Kananaskis Country at its peak, which Sandford compared to the development of a small city. 

“A town the size that they’re developing, that water footprint’s really heavy,” he said. “What are the downstream effects going to be?”

The proposed expansion is a far cry from the old days of Fortress. When the resort first opened in 1967 under the name Snowridge, the lodge could accommodate 140 overnight guests. Six condos were built in 1976.

The ski hill operated for decades, changing hands multiple times before closing to the public one last time in 2006. 

Now, Alberta’s 2024 All-season Resorts Act is giving it new life. The Alberta government says the act helps to grow the tourism industry, “strengthen investor confidence” and offer “tailored support to the resort development industry.” The Canadian Parks and Wilderness Society says the act means resorts can circumvent and undermine environmental laws. Under the act, areas are designated for streamlined approval for tourism projects.

Fortress is hoping to develop in one of three areas that were designated under the act in December. A fourth is under review. 

The five-phase vision for Fortress includes up to 9,650 day-visitors by completion and 1,500 employees, plus overnight visitors and staff in 2,500 on-site units that would be a mix of tourist accommodation, real estate and employee housing, along with at least 1,400 parking stalls. It would take 15 years to complete. 

Designating the Fortress site for an all-season resort required the removal of 131 hectares from provincial parkland, according to an analysis from the Canadian Parks and Wilderness Society.

The resort will include activities like electric all-terrain vehicles, mountain biking, minigolf, two “mountain coasters” (bobsled-like roller coasters), zip lining and more, along with infrastructure for more than 12 ski lifts, including five gondolas and five chairlifts. 

It’s what Katie Morrison, the executive director of the southern Alberta chapter of the Canadian Parks and Wilderness Society, describes as an “amusement park” in an area of ecological importance for sensitive wildlife like grizzly bears, wolverines and bull trout — all in an area already under strain from tourism.

For its part, Fortress says the project team is dedicated to sustainability.

“We aim to be the most water-efficient resort in Alberta,” project director Danielle Vlemmiks said in response to The Narwhal’s questions over email.

Vlemmiks said, should the resort decide to make snow in later phases, Fortress plans to use grey water for snowmaking, something done at other resorts, and is planning activities that do not require large water use.

But that doesn’t quell concerns from environmental advocates who have long been ringing alarm bells over tourism development in the Rockies — an area where wildlife habitat and headwaters are already under threat from clear-cutting, coal mining and more.

So, when Fortress released its plan in January, it was a “worst-case scenario,” Morrison said.

Resort act a ‘regulatory failure’: lawyer

The Fortress proposal and water use is a good example of the All-season Resorts Act’s shortcomings, University of Calgary law professor Shaun Fluker said in an interview with The Narwhal.

Under the act, decision-making power for some large-scale recreation projects has been given to the Tourism Ministry, which has set a goal to grow tourism revenues to $25 billion by 2035. It’s a system Fluker describes as a “fiefdom of the minister.”  

“There are no guardrails,” he said.

The All-season Resorts Act establishes a new kind of zone, an “all-season resort area,” which can be created by the tourism minister. After an area has been designated under the act, a developer can then submit an application for a proposed development, including an environmental assessment it has contracted. The proposal must also undergo a minimum 30-day public consultation and an Indigenous consultation period. The Tourism Ministry makes a decision within 150 days of the application being complete. 

Morrison said the entire legislative process, from tabling the act to implementing it, has been rushed. And she noted the decision-making power lies with the same ministry mandated to increase tourism development, which she says is problematic, particularly under a fast timeline. 

“It’s a little bit of the fox watching the hen house,” Morrison said. “Some of the reasons we have had delays in approval on these things is because this is a really complex landscape.”

As it stands, Morrison said, the environmental assessment Fortress supplied as part of its application lacks critical information, and is “woefully inadequate” in addressing the potential impacts of the development. Bull trout, a threatened species in Alberta, have specifically been “completely ignored” by the report, she said, as has information needed to understand the impacts of the development on wildlife, aquatic ecosystems and water use in the region.

Fluker said the inadequacy of the assessment, which every expert in this story agreed lacked information for decision-making, “undermines the whole approval process.” 

“No credible impact assessment process would take that as a final submission because there’s really nothing usable in it,” he said. 

As a requirement, an assessment should put forth enough data for experts to evaluate the potential impacts of a project and come up with solutions. 

With this assessment, he said, “I don’t know how anybody could do that.” 

Details like how much water the resort would need to operate are currently being studied, Vlemmiks said. But, because Fortress is planning to be as economical with its water use as possible, the needs of the development will have to align with the project design, which will not be finalized for some time.

According to the assessment, and confirmed by Vlemmiks, Fortress has enough water for phase one of its five-phase plan, which anticipates 3,000 day-use visitors. Beyond that, more water may be required. 

According to a briefing note from the Tourism Ministry dated June 19, 2025, and obtained through a freedom of information request, the government is well aware of concerns with how the act will deal with water issues in particular. 

“[The Ministry of Environment and Protected Areas] has previously raised concerns about how [all-season resorts] will align with water management priorities, especially in light of recent droughts in southern Alberta,” the note reads. 

But, it adds, “these concerns are addressed” through a system where Tourism and Sport will share water management responsibilities at resorts alongside the Environment Ministry. 

The system is a red flag to Fluker.

Concerns should be brought to and evaluated by an independent board of scientific experts, he said. (The Alberta government did not respond to detailed questions from The Narwhal.)

“That is exactly the kind of issue or topic that a credible impact assessment process grapples [with],” he said. 

Morrison agrees, adding she was surprised water didn’t play a bigger role in the proposal — especially given Fortress’s history with water use.

Water from resort is currently sold as bottled ‘glacier water’

Alberta is in a multi-year drought, with conditions across the province ranging from “abnormally dry” to “severe drought.” Forty water shortage advisories were posted in April 2026. But southern Alberta has a long, complex history with drought and water management, including in Kananskis Country.

Alberta has seen two or three seasons of significant water shortage in the last 20 years, Cathy Ryan, a University of Calgary professor in earth, energy and environment, said. 

In times of drought, the main concerns are increased wildfires and sufficient water supply — for residents, visitors and ecosystems, Ryan said.

Water supply is managed by the province through a licence system that grants users the right to divert water whether from below ground or from rivers, lakes or streams.

Fortress is part of the vast Bow River Basin — which is itself within the South Saskatchewan River Basin drainage area. The Bow River flows through Banff National Park and eventually merges with the Oldman River to form the South Saskatchewan River. From there, it moves across the Prairies toward Medicine Hat in southern Alberta and beyond. 

The sale of new water licences in the South Saskatchewan River Basin, where Fortress is located, has been prohibited since 2006. But Fortress Mountain Holdings has two licences, one of which is for potable water. 

In 2019, Fortress was given the green light to sell half of the 98,700 cubic metres, or just under 40 Olympic swimming pools, of its potable water licence commercially. The change was opposed by environmental groups and lawyers and was challenged — unsuccessfully — by Stoney Nakoda First Nation in court in 2020. Canned water from Fortress is now sold as rök Glacier Water.

Should the resort proposal be approved, Vlemmiks said Fortress will cease commercial water sales.

She said the company plans to create a closed-loop system on site. That could include geothermal heat, greywater-supplied snowmaking and reusing water, though she did not provide any further details.

Vlemmiks also said Fortress is exploring a partnership with Stoney Nakoda First Nation to supply and manage water for subsequent phases, and is currently undergoing an Indigenous consultation process. Stoney Nakoda First Nation did not respond to a request for comment.  

“We are actively pursuing answers,” Vlemmiks said. 

But critics warn even the best-laid plans are subject to a changing climate — and declining water resources.

 Concerns about water shortages in Kananaskis Country

When it comes to divvying up water, Cathy Ryan from the University of Calgary said it’s been managed so far by “playing nicely in the sandbox.” But in the event of a shortage, the government can step in to manage water supply.

It’s happened more than once in the last 20 years. Most recently, in April 2024, Alberta instituted water-sharing agreements, where 38 of the largest water-licence holders — making up 90 per cent of the Bow and Oldman basins and 70 per cent in the Red Deer basin — agreed to voluntarily reduce water use if severe drought conditions developed due to several dry seasons and an El Niño winter.  

But water-sharing agreements are voluntary. 

In 2006, more drastic measures were taken: the province stopped the sale of new water licences in the over-allocated South Saskatchewan River Basin to protect the aquatic ecosystem and ensure Alberta could meet its water-sharing obligation with neighbouring provinces.

According to the province’s online tool, the Bow River Basin, where Fortress is located, was considered in moderate drought in February. 

In January, United Nations and Global Affairs Canada released a report about water bankruptcy, defined as when sustained water withdrawal exceeds replenishment, akin to spending outpacing income. Sandford, with the United Nations water think-tank, warned southern Alberta is already headed toward water bankruptcy. 

As climate change increases temperatures and exacerbates the effects of drought, Sandford’s concerns are far-reaching.

Fortress’s proposed development will land amidst a sea of warning signs outlined in the report, Sandford said. Southern Alberta ticks every box, he added, including infrastructure, long-term over-allocation of water and what’s known as ecological liquidation, when wetlands and forests are degraded for short-term gain.

Sandford said the province needs to plan for the persistent high temperatures, extreme drought and low snowpacks it is already seeing, and the impacts. Multiple wildfires have already been reported in southern Alberta since the beginning of the year. 

And as soil moisture dries up, rain won’t have the same penetrating effects, resulting in a “vicious circle of drying out,” Sandford said.

“You’re taking away the environment’s share of water,” he said. “Even at this moment, without the projected changes that we’re seeing, I don’t think they can do this.”

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

Summary

• The Government of Ontario is overhauling the mine permitting process to funnel all stages through the relatively new Ministry of Energy and Mines, under the “one project, one process” system.
• Many First Nations leaders have voiced concerns about how this will impact consultation, and the burden it places on Indigenous communities.
• Some mining companies are already seeing how this fast-tracking could play out, and say no corners will be cut.

In early March, dozens of digital billboards across Toronto’s Union Station repeatedly flashed four words that have become synonymous with economic survival for the Doug Ford government: “one project, one process.”

The phrase welcomed people travelling through the central transit hub on their way to the world’s largest annual mining conference, held by the Prospectors and Developers Association of Canada. It was an overwhelming four-day affair, where more than 32,000 people talked deals, investments and pretty rocks in faraway places and how to get them out of the ground. 

This year’s conference — the largest ever — began a day after the United States and Israel attacked Iran, setting in motion a crippling squeeze on oil supply that has raised gas prices to levels not seen in decades and killing thousands of people. But that didn’t hamper the very loud buzz at the conference. In some respects, it may have upped the volume.

The urgency for a homemade solution to tackle global crises (mainly Donald Trump) had increased once more — and Ontario had a (four-word) plan that is still, for all the fanfare, an untested experience, unknown to many.

Though outward-facing, the plan is actually predicated on reshaping the way the government works internally, to guide and greenlight proposals for mining and development faster through the bureaucracy. The promise: one project ushered through one massive, clear and quicker process. 

“It’s a huge shakeup,” one former Ministry of Mines official told The Narwhal. “It’s a huge disruption from how we would all typically work.”

The enormity of this internal shift was evident in the sprawling halls of the Metro Convention Centre. There, government ministers, led by Energy and Mines Minister Stephen Lecce, met seemingly every global delegation with the message of “one project, one process” — colloquially called “1P1P” — and how it would turn Ontario into “the world’s reliable partner.” Ministry staff answered questions in packed rooms about how to figure out if “1P1P was right for you.” The three companies that had already been accepted into the fast-tracking process were the stars of a crowded trade show, including one that talked at length with The Narwhal.

While expediency might yield positive results for the mining industry, for some First Nation leaders who attended the conference, there is an obvious loss: important things, like consultation and consent, could also be fast-tracked, or missed completely. There was also frustration over the many crises that, for decades, have not been granted the same urgency: clean drinking water, basic health-care services, housing. 

“We still don’t have any clarity on what fast-track or ‘one project, one process’ really means,” Ontario Regional Chief Abram Benedict told The Narwhal. “We’re all still kind of unsure.” 

Four other First Nations leaders told The Narwhal the same thing: no one in government had talked to them yet about the process, let alone what it means for their communities, which are already on the frontlines of resource extraction and its aftermath. 

The next 12 to 18 months, Benedict said, will “become the real test” of the government’s four-word fast-tracking policy, both provincially and nationally.

‘A trailblazer or a guinea pig’

Just outside Red Lake, Ont., 100 kilometres east of the Ontario-Manitoba border, is the proposed site for the largest lithium mine in the province. The company hoping to build it, Frontier Lithium, says the mine could help supply electric-vehicle battery manufacturers. It was the first project to be designated on Ontario’s “one project, one process” list. The Sudbury-based mining company was assured a 24-month approval by the Ford government. 

“We’re either a trailblazer or a guinea pig,” Clara Lauziere, Frontier Lithium’s director of sustainability, told The Narwhal.

Three years ago, Lauziere was working in the Ministry of Mines, navigating a process she described as inefficient and uncoordinated. “Had I known 1P1P was coming, I might have stayed,” she said. 

As she explains it, the regulatory system in Ontario and Canada has some of the highest environmental standards, but it’s also one of the most complex globally. “There’s never been a real road map on how to permit a mine and how to do it effectively,” she said, because every project is different. Until last October, mining companies had to work with multiple ministries that didn’t communicate well, which she said resulted in a lot of repetition and confusion for both industry and Indigenous communities. 

“Consultation fatigue was huge,” she said. Some of the communities she spoke to as a ministry official had received six or seven letters from several different ministries about the same project. In the same vein, companies were receiving multiple directives from different ministries about which Indigenous communities to consult about different parts of the project. 

All of this inevitably resulted in delays for permits; 15 years of delay, according to the Ford government, though it hasn’t given examples of when bureaucracy alone tangled a mining project up for that long. With the new process, that will purportedly go down to two years. “Certainty is everything,” Lauziere said, “especially when you’ve never had it.” 

That’s why she was bombarded with questions in every room she went to at the conference. “People want to know if they can really believe this is actually going to happen,” she said. The short answer appears to be yes, but it depends on a sustained commitment from industry to also be ready and committed with the right paperwork, detailed studies, accurate data and robust consultation plans. “I think the key is really just being willing to work with the government and communities,” she said. 

In other words, as a government official told a packed room at the mining conference, “this is not a one-way street” but “a tremendous effort that requires everyone to be at the table.”

When Frontier Lithium was accepted into the new system, the company “had everything ready,” Lauziere said. In response, they were assigned a bureaucrat to be their main point of contact throughout the process, leading a team of officials across ministries. The company was provided a detailed 24-month timeline of steps this team would be completing in partnership with them. 

In early March, the Independent Electricity System Operator, the Crown agency in charge of electricity supply and demand, proactively reached out to Frontier Lithium to discuss energy needs for their proposed mine after the company was selected for fast-tracking. “So there’s a lot of coordination and pressure there on priority projects,” Lauziere said, including from the mining minister himself. 

In mid-March, Frontier Lithium received a single directive identifying all the communities that need to be consulted for the entire project. “Now, we can have confidence that we know who we need to talk to and what the potential impact on rights are going to be, so we can have meaningful conversations,” Lauziere said. “That level of detail and consolidation is incredibly valuable for communities and companies.”

Frontier Lithium is expecting a permit by the fall of 2027, so the new process does appear to be faster. Lauziere said if any concerns crop up with their proposal over this period, the company expects to resolve them with the government and communities. 

“No corners are cut in the process,” she added. “And nothing changes on the consultation front.” What “one process, one project” does is make the consultation process clearer for every company. 

“Yes, we want to build a mine,” Lauziere said, “but we also want a relationship that lasts 50 years.” 

“As the first, we all kind of have to get it right.”

Fear of the fast track

Ontario’s push to fast-track mines, and promises it can happen without sacrificing free, prior and informed consent from First Nations, hasn’t landed with everyone. 

“The idea of fast-tracking really scares me,” Natasha Martin, Deputy Grand Chief of Mushkegowuk Council, told an overflowing room of miners and government staffers at the March conference. 

She repeated the same sentiment to The Narwhal in an interview later. “That means that it’s a very fast job — a rush job — and we’re taking something that has taken years prior down to six months. That scares me, because then there will be things that won’t be properly captured or looked at.”

Martin’s fear highlights a deep disconnect in the ways industry and First Nations understand “one project, one process.”

While companies are quickly gaining extensive knowledge of what it all means for them, many First Nations say they have been left in the dark. And they remain especially skeptical about the effectiveness of environmental and community risk assessments under the streamlined process. In no small part, because it was initially proposed in Bill 5, a controversial legislation that allows for “special economic zones” where “designated projects” can evade provincial laws.

Bill 5 was written without the government holding a single consultation with Indigenous communities, although many would be significantly impacted by an increase in mining and development activity — and have historically not reaped the financial or social rewards of such industry. Nine First Nations have challenged the law in court, arguing that it is unconstitutional.

Complicating matters further is that just as Ontario speeds up development approvals, the federal government has created its own office with a similar mandate. The Crawford Nickel project, outside Timmins, is being considered for fast-tracking at both levels. And recently, Frontier Lithium has been named to another list of projects for “federal permitting coordination.” 

On the one hand, Lauziere credits the “one project, one process” system for setting them up perfectly for federal fast-tracking. On the other hand, early signs show choppy collaboration between levels of government could be a new drag on momentum, even as First Nations around Red Lake appear ready to work with both.

Lauziere agreed that if things are going to be sped up, there will inherently be added pressure on First Nations. She called it “an unintended consequence” that will require Ontario to actively work on better informing and communicating with Indigenous communities. 

“We really haven’t seen much of a difference on the ground yet,” Jason Batise, the executive director of the Wabun Tribal Council, told The Narwhal. The regional council for five First Nations around Timmins has honed a consultation framework to manage the deluge of mine consultations over the last two decades. That includes Crawford Nickel, with whom Batise says the First Nation has a good relationship.

Batise is clear: “Consultation has never been a bottleneck to responsible development.” 

“We don’t really yet see any sort of distinct acceleration of 1P1P, but we know it’s coming,” he said. “And if I had one concern, it would be the expectation from developers to fast-track consultation.” 

“Because at that point, 1P1P is going to get challenged by the nations.” Historically, mining projects have been delayed by protests or legal challenges from nations that feel their constitutional rights were not properly met.  

Batise isn’t the only one watching the fast-tracking process carefully. Many Indigenous leaders came to the mining conference with messages of vigilance, reminding attendees that First Nations were not “carbon copies,” and neither are their territories.

Even as the process to approve mining projects speeds up, communities like Neskantaga First Nation, in the Ring of Fire region, are dealing with simultaneous crises. When Bill 5 passed, the nation’s only health-care centre was flooded and inoperational. There continues to be a chronic housing shortage; those that are standing are plagued by mould. There is a 31-year boil advisory in effect, the longest in the region. 

“It’s hard to understand. It’s moving so fast,” Chief Gary Quisses told The Narwhal at the mining conference. He fears that despite its moniker, the “one project, one process” system will open the doors to multiple projects in their communities that all bypass First Nations consent, and needs. 

“I don’t even have 9-1-1, I can’t even use that number. I don’t have a fire truck. I don’t have an ambulance, paramedics, anything,” he said. “And here, the government is trying to push and take our resources away.”

Batise is cautiously hopeful, noting that industry has lately had its “come-to-Jesus moment with First Nations,” developing meaningful partnerships based in equity. But he too worries the fast-tracking process may become a catalyst for companies to prioritize their bottom line. 

“The government is telling industry 1P1P will be better for them. They’re also telling nations that faster is better for them,” he said. “The difference is that industry is getting what they want, but communities are not.”

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.

Table of contents

• Step 1: Begin in a time of crisis
• Step 2: Get to know the region’s permafrost — and assume ‘the ground is going to move’
• Step 3: Prepare to build a pipeline above-ground — or chill the oil
• Step 4: Expect cost overruns, especially as the climate changes
• Step 5: Monitor in perpetuity. Adapt to a warming climate

“This is no picnic,” warned a somewhat cryptic job poster on the walls of an Edmonton pipeline construction firm in summer 1942.

“Men hired for this job will be required to work and live under the most extreme conditions imaginable. … Men will have to fight swamps, rivers, ice and cold. Mosquitos, flies and gnats will not only be annoying but will cause bodily harm. If you are not prepared to work under these and similar conditions — do not apply.”

The job was a secretive government project in the wilderness of the Canadian North. In less than two years, a team of 30,000 would enlist to lay a four-inch-wide steel pipe from a recently discovered oilfield near Norman Wells, N.W.T., to Whitehorse, Yukon.

The “stupendous” and “unusual” construction project, as it would be called in the years after its completion, was the first attempt to build a pipeline in the North American Arctic. 

It would ultimately lay the foundation for many decades of oil exploration in the North.

Today, a fragmented trade relationship with the United States and an oil crisis driven by a new conflict in the Middle East have bolstered Canadian politicians’ calls for new oil and gas infrastructure.

As investors hesitate to back the east-west pipeline proposals that face opposition from Indigenous communities and environmental advocates, a decades-old idea to build a link to the Port of Churchill on the shores of Hudson Bay has picked up steam.

While not all of northern Manitoba is as ice-laden as the Northwest Territories or Alaska, any pipeline from Alberta’s oilfields to Manitoba’s northern coast would need to cross the Canadian Shield, the tundra and permafrost. These ecosystems are changing rapidly as the planet warms; more than half of existing infrastructure in the Arctic is projected to incur damages by mid-century as a result of climate change. 

If Manitoba, the federal government and industry players are serious in their pursuit of pumping oil and gas through the Port of Churchill, they will need to build on the legacies — and lessons — of northern pipelines that have come before.

Step 1: Begin in a time of crisis

The first time a pipeline was strung across the hard, icy wilderness of the North American Arctic, the world was at war. 

It was the spring of 1942, just months after the attack on Pearl Harbor, and the U.S. War Department (as it was called then, too) was concerned its Arctic bases were exposed to attacks by Japanese forces. 

Behind closed doors, the U.S. government devised a plan to shore up its Arctic security with two daring infrastructure projects: a highway slicing through the ice from Dawson Creek, B.C., to Delta Junction, Alaska, and a pipeline feeding crude from the untapped Norman Wells oilfield in the Northwest Territories across the Mackenzie Mountains and on to a refinery in Whitehorse.

This secret wartime pipeline, built by the Imperial Oil Company, would be called Canol — short for Canadian oil. 

“At the time Canol was begun, our situation was not a happy one. … The sea lanes to Alaska might be blocked, and with a shortage of freighters and tankers it was imperative that an overland route to Alaska be opened up and given an assured fuel supply,” Richard Finnie, a historian and filmmaker who produced a documentary about the pipeline, said in a 1947 article in the Canadian Geographical Journal.

“All that was done, and with amazing speed.” 

It took just 22 months to lay the 1,000-kilometre pipeline; it would take just nine months to abandon it. By 1947 the war was over and the oil link was no longer needed. Canol was dismantled, its steel repurposed. 

But its short-lived presence made a permanent mark on the North.

Before Canol, Finnie said, there were no airports, no roads longer than 15 kilometres, and certainly no oil infrastructure. The project proved to governments, business and engineers that the harsh northern terrain, with its unyielding granite and ice, could be tamped down with concrete and steel. 

In the decades since, two more major pipelines have been built in the northern reaches of the continent: Enbridge’s Line 21, from Norman Wells to northwest Alberta, and the Trans-Alaska Pipeline System that cuts the length of the northernmost American state.

The Trans-Alaska pipeline, a four-foot-wide, 1,200-kilometre-long pipe that zigzags through Alaska’s mountain valleys from an oilfield at Prudhoe Bay to a marine terminal at Valdez, was also built in just two years. It had previously been stalled for several years due to legal and environmental challenges, but was ultimately approved when the 1973 Arab-Israeli war thrust America into an oil crisis.

Now, a new oil crisis is renewing old interests.

Amid what the International Energy Agency called “the largest supply disruption in history,” Canada has agreed to contribute 23 million barrels to global emergency oil supply. Despite being the world’s fifth-largest producer of both crude oil and natural gas, pundits and politicians argue a lack of pipelines is stymying the country’s export capacity.

“We must build new pipelines west, east, north and south — without delay and without hesitation — to supply Asian, European and American markets with safe, reliable and responsibly produced energy products,” Alberta Premier Danielle Smith wrote in an op-ed for the Financial Post this month. 

Manitoba’s Port of Churchill is now being heralded as a potential trade hub allowing the country’s resources more rapid access to eastern markets. Momentum is building in support of an energy corridor that could carry oil, natural gas, potash or hydrogen from the Prairies to Hudson Bay. 

In January, Premier Wab Kinew announced multiple energy companies are interested in backing the proposal, while a November agreement with the federal government pledges to simplify regulatory approvals for a port expansion.

In the 2026 budget, the NDP announced a further $10 million to “keep building the momentum on this project and attract even more private sector interest in a potential energy corridor.”

Under these political conditions — and with significant investments from either the private or public sector — pipelines can be built quickly. 

“There’s just an idea that we don’t do enough in the Arctic,” Heather Exner-Pirot, director of energy, natural resources and environment at the Macdonald-Laurier Institute, said in a late February interview. Canadians periodically worry the country does not have enough presence in the Arctic, or is under-utilizing its resources, she added. 

Those fears are “based on a very superficial understanding” of the Arctic, she said. But coupled with a desire to diversify exports and opposition to an east-west pipeline through B.C. to the Pacific Ocean, they have made the prospect of a new northern pipeline more enticing.

But in reality, she said, building in the North — over Manitoba’s muskeg and permafrost — is an expensive and dangerous logistical challenge.

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Step 2: Get to know the region’s permafrost — and assume ‘the ground is going to move’

When Canol was first proposed, scientists knew so little about building infrastructure in the Arctic, they had yet to come up with a term for its characteristic, perennially frozen ground. It was Stanford University professor Siemon Muller who first coined the term permafrost after being sent to investigate where the Alaska Highway and Canol pipeline would be built.

In simplest terms, permafrost is a term for ground that remains frozen year-round, though it is formally defined as “earth materials that remain below 0 C for two or more consecutive years.”

Permafrost is typically described as either continuous (appearing over more than 80 per cent of the ground), discontinuous (covering between 30 and 80 per cent) or sporadic (less than 30 per cent). Almost half of Canada’s land area is underlain with permafrost, predominantly across the Territories. 

While the top layer of soil, called the active layer, thaws briefly in the summer, the permafrost below remains at a relatively stable freezing temperature. Gravelly, rocky soil is often considered “ice-poor,” and is able to maintain its stability even when the ice thaws. Finer soil tends to create “ice-rich” permafrost, where frozen moisture is necessary to the structural integrity of the surface. 

Understanding these nuances is a prerequisite to designing any pipeline infrastructure in the North, University of Alaska Fairbanks geophysicist Vladimir Romanovsky said in an interview. 

“If it’s present, the second very important question is: how much ice is in that permafrost?”

Romanovsky has been working with permafrost since the mid-’70s — right around the time the Trans-Alaska pipeline was built. Understanding of permafrost was still limited then, but would grow as engineers planned a route across the Arctic. 

In January 1969, representatives from some of North America’s largest oil and gas producers and mining operations met at the University of Calgary for the third Canadian conference on permafrost, where a session was dedicated to discussing the challenges of building pipelines over the frozen ground. 

By this point, scientists understood the permafrost “is in a very delicate state of thermal equilibrium with its environment, and any disturbance will cause thawing and degradation,” T. A. Harwood, chairman of the National Research Council’s permafrost subcommittee, said in a presentation. This is further complicated by the discontinuous nature of much of Canada’s permafrost layer, he added, which makes the ice “patchy and unpredictable.” 

Understanding the ice content helps engineers assess how the permafrost will change under the temperature stresses created by a pipeline, Romanovsky said. Oil pipelines are usually transporting a heated product, while gas pipelines are often chilled. 

“Both of them impact the environment in terms of permafrost. The heated oil pipeline will thaw permafrost if it’s placed into the ground; the chilled gas may actually create new permafrost,” he said.

When permafrost thaws, a layer of water forms under the ice, which can cause the ground to shift — a phenomenon called subsidence. The problem is exacerbated on slopes, where the soil can become oversaturated and form landslides. Newly frozen areas can swell or heave, posing infrastructure risks. 

“Permafrost, generally, is not just frozen dirt. It’s a highly sensitive, temperature-dependent foundation,” Alireza Bayat, professor of civil engineering and director of the Canadian Underground Infrastructure Innovation Centre at the University of Alberta, said in an interview.

As the active layer thaws and freezes, the changing grounds can cause pipes to either sink into the soil or be pushed up out of the ground, Bayat said.

“Essentially you’re assuming the ground is going to move. How can we build or design a pipe that’s able to handle that?”

To make a pipeline work in the discontinuous permafrost seen in northern Manitoba, Romanovsky said scientists and engineers will need to consider the extent of the ice layer and calculate the degree of cooling needed to keep the frost stable through the pipeline’s lifespan. Extra margin should be built in to account for climate change, he said, which is rapidly warming the Arctic.

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Step 3: Prepare to build a pipeline above-ground — or chill the oil

After finding a major oilfield at Prudhoe Bay, Alaska, in the 1960s, oil and gas executives were consumed with “the problem of deciding on the best means of transporting this oil to market.” 

In his presentation, Harwood suggested a couple possible routes: either straight across the permafrost to Alaska’s south shore, or through the Mackenzie River Valley. The latter seemed the more sensible option to Harwood, given the pipe could either link up with existing infrastructure in Alberta or be carried on to the Port of Churchill — which was being used for seasonal grain shipments at the time — where “it appears reasonably certain that it would be possible to ship oil … to any continental port throughout the year.”

The decision would ultimately be made to run the pipeline across Alaska, allowing easier access to western markets and fewer regulatory challenges. 

But the question of how to lay a pipeline carrying either hot, liquid oil or pressurized, cold gas was still unanswered. 

At that point “no one [had] actually constructed a pipeline in the North and operated it,” Harwood said.

He proposed three solutions: building a road with a large crown — effectively a peak in the centre — along which a pipeline could be nestled in insulating materials, laying the pipe in a trench dug into the active layer of the permafrost or suspending the pipeline above ground. 

The original design for the Trans-Alaska pipeline was drawn up by a Texas company that planned to use the same methods it had for its southern lines, Romanovsky said: “Dig a trench, put the pipe in, cover it and everything will be good.” 

“That would be a disaster if that would have happened,” he said.

The design was reviewed by Arthur Lachenbruch, a permafrost scientist at the United States Geological Survey, who determined the proposal to bury a four-foot-wide pipe the length of the state would likely thaw the surrounding permafrost.

“Where the ice content of permafrost is not high, and other conditions are favorable, thawing by the buried pipe might cause no special problems. Under adverse local conditions, however, this thawing could have significant effects on the environment, and possibly upon the security of the pipeline,” Lachenbruch wrote in a 1970 report.

Lachenbruch’s report changed everything, Romanovsky said. 

The pipeline was already facing pushback in the courts from both environmental organizations and Indigenous Alaskans. It was the first major test of the newly passed National Environmental Policy Act, and led to lengthy environmental impact assessment hearings, where critics used Lachenbruch’s report to support their case.

Construction stalled while the pipeline owner, now called the Alyeska Pipeline Service Company, was forced back to the drawing board. 

Instead of burying the line, engineers decided to suspend more than half of the 1,200-kilometre link on H-shaped support beams, a novel construction method for the time.

The 78,000 beams were each fitted with an innovative technology, called thermosyphons, designed to regulate the temperature of the permafrost.

“It’s a very smart engineering design,” Romanovsky said. 

The thermosyphons (also called thermopiles) don’t require any energy. Instead, the space-age technology consists of sealed tubes inserted several metres into the permafrost that contain a small amount of pressurized gas.

In the summer months, when the permafrost is colder than the air, the thermosyphons don’t have much work to do. But in the winter, when the temperature below ground is warmer than the atmospheric temperatures, the gas condensates into a liquid and drips to the bottom of the tube. Below ground, the liquid absorbs heat from the surrounding ice and evaporates, drawing the heat up and out to the surrounding air. 

“This convection goes on all winter long, taking heat from the ground, bringing it to the atmosphere and releasing it,” Romanovsky said.

Years after the Trans-Alaska pipeline came online, Canadian oil companies returned to the idea of laying a pipe through the Mackenzie Valley, this time connecting the oilfield at Norman Wells, N.W.T., to existing infrastructure in Zama, Alta. 

Unlike the Trans-Alaska line, Enbridge’s 869-kilometre Line 21, which came online in 1985, is the first Canadian Arctic pipeline to be buried in the permafrost.

To mitigate the risk of subsidence, the Norman Wells pipeline runs cold. The oil is chilled before entering the line to mirror the average ground temperature throughout the year, averaging between 0 C and -1 C. (Oil in the Trans-Alaska line is kept between 38 C and 63 C). 

Because clearing the ground for a pipeline right-of-way removes some of the natural insulation on the permafrost, several thaw-sensitive slopes along the route were insulated with woodchips to prevent melting. Monitoring technology was installed in strategic locations to measure ground temperature, check for pipe movement and estimate thaw depths. 

The pipeline has not been without incident. 

1,500 barrels of oil spilled after the pipe failed in 2011. Two years later, the federal pipeline regulator found 77 buried lines in the region were at risk of failure; the town of Norman Wells ranked as the community with the highest number of federally regulated pipeline incidents in 2013. In 2016, the pipe was shut down for nearly two years due to risks posed by a shifting permafrost slope.

Imperial Oil plans to “wind down” operations at the Norman Wells oilfield this fall, citing declining production.

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Step 4: Expect cost overruns, especially as the climate changes

Regardless of whether the pipe is to be built above or below ground, designing and constructing infrastructure able to withstand shifting permafrost is, above all, “very expensive,” Romanovsky says. 

At the earliest stages, a feasibility study estimated the Trans-Alaska pipeline would cost between US$863 million and $1.05 billion, depending on its capacity. By 1975, after re-working the design to factor in the permafrost, the budget was $6.4 billion. 

In the end, it cost more than US$8 billion —10 times the original estimate. 

Similarly, Canol came with an initial estimate of $500 million (in 2025 CAD) but in the end cost $3.2 billion. After the war, American cabinet members criticized the project as “useless and a waste of public funds.” 

These ballooning costs are often attributed to the limited permafrost expertise during initial designs; they do not account for the additional costs of maintenance and repair.

Bayat, at the University of Alberta, said Arctic pipelines require specialized materials, design characteristics and construction methods to withstand the forces caused by moving permafrost while mitigating the pipe’s risk to the environment — all of which can be costly.

The remote location can also add to the cost, as it leaves operators reliant on winter roads and other temporary infrastructure when building and maintaining the pipe.

“You will spend some money to keep it in good shape,” Romanovsky, at the University of Alaska, said of Arctic pipelines.  

For example, the company tries to survey the pipeline by helicopter every day, weather permitting.

When the Alaska project was being designed in the mid-’70s, Romƒanovsky said, engineers and geophysicists were concerned about how the pipeline could impact the permafrost, but few were aware of the long-term risks a warming climate could pose to the pipe itself.

In 2020, several supports holding the pipeline aloft began to bend as the permafrost slope they were attached to began to thaw and shift, threatening the integrity of the pipe and forcing the ownership group to replace the beams and refreeze the slope. The same year, flood damage cost the operators US$10 million to repair the pipeline, while preventative maintenance to safeguard sections against further flooding was expected to cost a further $10-15 million.

These expenses are expected to climb as warming accelerates permafrost thaw. 

A scientific review of research from the last 20 years estimates as much as 50 per cent of Arctic infrastructure — including the Trans-Alaska pipeline, and some Canadian highways — are at high risk of damage by 2050. Maintenance costs, the review estimates, could increase by more than $15 billion in that time, while unavoidable damages could cost upwards of $21 billion.

Manitoba has already felt the impacts of shifting permafrost on infrastructure. 

The Hudson Bay Railway, which runs more than 800 kilometres between The Pas and Churchill, was among the first major transportation projects built over Canadian permafrost. Since its construction in the late 1920s, it has required regular maintenance as the weight and heat of train traffic thaws the ice-rich permafrost over which it was built. The railway was out of service for 18 months after being washed out by floods in 2017.

Federal and provincial governments have spent upwards of $500 million to purchase, repair, maintain and upgrade the railway since 2018.

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Step 5: Monitor in perpetuity. Adapt to a warming climate

As part of the environmental agreement that greenlit the Norman Wells pipeline, Enbridge and the Canadian government collaborate on research and monitoring, which provides long-term data about the impact of pipeline infrastructure on the permafrost.

That data is among the longest permafrost monitoring records in the country. The long view of the ice helps form a picture of how permafrost is changing alongside the global climate — and trends show the ice is warming quickly, Romanovsky said.

“In places where the permafrost was warmer, it’s already started to thaw from the top down,” he said. “In the future, with further warming, it will be happening in more and more regions, and be happening faster and faster.”

A 2024 report from the Arctic Monitoring and Assessment Programme found permafrost has warmed by two to three degrees since the 1970s, as ground temperatures reach record highs. The thawing has substantial impacts on the landscape, causing erosion, slumping and pooling of water. That melting permafrost in turn releases trapped carbon dioxide, further fuelling the warming effect.

The Arctic Research Consortium of the United States warns the standard 30-year climate data engineers typically use when planning infrastructure projects has become “insufficient,” as climate change speeds up. 

“In the past, pipe design was kind of static … they were based on the fact we know how the weather is or how the ground is,” Bayat said. “Those assumptions are now more dynamic and they are changing with the climate.”

These warming trends could render existing mitigation technologies like thermosyphons ineffective, Romanovsky added.

During an engineering conference in Portugal in 2008, Edmonton-based Duane DeGeer presented on the unique considerations for Arctic pipelines, reporting the success of both the Norman Wells pipeline and the buried segments of the Trans-Alaska line had “prompted pipeline designers to consider burying Arctic pipelines wherever possible.” 

To mitigate heaving and sinking, the report referred to research on thicker, stronger, better insulated pipes, as well as controlling the temperature of materials inside, varying burial depth and soil cover and, above all, conducting long-term monitoring of soil temperatures and pipeline integrity. 

According to Bayat, more resilient materials, better temperature control methods, as well as more advanced monitoring technology, have become more accessible over time. 

Engineers now use a “strain-based design” philosophy that accounts for the inevitable ground movement caused by permafrost, and plans for pipes that can withstand those forces, he said. Construction practices have also evolved, with directional drilling (an underground tunnelling technique) replacing the traditional open-trench methods.

Major strides have been made in monitoring technology, he added, with fibre optic sensors, digital inspections and predictive analytics that “allow us to have more eyes on those pipes and be more proactive than reactive.” 

Ultimately, Bayat said, building a new pipeline in the North will come with many unknowns.

“This is not the area [where] we go and build pipes every day. … When it comes to the North, yes we have examples, but only a few, and they’re from the past,” he said. 

“These foundations are rapidly changing. What will the pace of that change be? How much further is it going to change? Those are the things that need to be taken into account.”

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

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

Nova Scotia’s Kejimkujik National Park and Historic Site is home to old-growth forests, white sand beaches, diverse wildlife and abundant natural beauty. But long before it was established as a national park in 1969, it was the site of Mi’kmaw fishing villages, hunting territories and burial grounds for thousands of years. Now, the Mi’kmaq will once again play a central role in deciding how that land, which is the keeper of their stories and memories, is cared for.

A new agreement between the Mi’kmaq and Parks Canada will allow both parties to govern almost all of Nova Scotia’s parks and historic lands together. Announced in December 2025, the Toqi’maliaptmu’k Arrangement, which means “we will look after it together,” reflects a relationship based in mutual respect and allyship — one that has taken decades to nurture and create.

Roughly 30 years ago, that relationship was essentially non-existent, Eric Zscheile says. He has been a legal advisor to the Mi’kmaq, who operate as one nation, since 1992 and negotiates on their behalf with the federal and provincial governments. 

Nova Scotia’s national parks (excluding Sable Island), as well as many more throughout Canada, were created from land that was directly taken from First Nations, often through “dubious land surrenders,” Zscheile says. For generations, the Mi’kmaq had no say in how unceded land was protected, used or accessed, and there was a deep sense of distrust toward the federal agency as a result. 

 “Most Mi’kmaq refused to even go into a national park because of the past,” Zscheile says. “There was a feeling that it was government appropriation.”

Then came the Marshall Case, a 1999 landmark decision in favour of Mi’kmaw fisherman Donald Marshall that affirmed First Nations’ Treaty Right to fish, hunt and gather for their livelihood. After that, Zscheile says, things slowly began to shift.

“ People within Parks [Canada] started looking at what was happening legally when it came to the rights of Indigenous Peoples and their relationship with Indigenous Peoples, not just in Nova Scotia but across the country,” he says. “There started to be a concerted effort to say, ‘I think we have to do things differently.’ ”

In the years since, progress has been gradual. Mi’kmaw leaders have worked with Parks Canada on a number of projects to help repair the community’s relationship with both the agency and the land they’d historically been excluded from. In 2012, they formed an arrangement to allow Mi’kmaq to enter national parks for free.

They’ve also worked to incorporate Mi’kmaw place names into official signage and interpretive displays, create visitor programs highlighting Mi’kmaw history and culture and organize harvesting, protection and restoration projects. One such project focused on white birch conservation and gave the Mi’kmaq access to white birch for traditional crafts, including building canoes.

Today, Parks Canada is lovingly seen by the community as the “least offensive federal agency,” Zscheile says. That’s thanks to years of collaboration and a willingness to listen and work together as equal partners. 

That status as equal partners is now official, according to the Toqi’maliaptmu’k Arrangement, which took nearly a decade of negotiations to bring to fruition.

The arrangement is unprecedented and monumental in its scope. While similar agreements exist in Gwaii Haanas in B.C., Newfoundland’s Torngat Mountains and Saoyú-ʔehdacho in the Northwest Territories, those partnerships apply only to individual parks. This agreement’s underlying principle is to recognize and implement Aboriginal and Treaty Rights within lands that have traditionally been governed, managed and utilized by the Mi’kmaq. 

Because of that wide scope, it’s the first agreement to apply province-wide and covers all Parks Canada-administered national parks and national historic sites in Nova Scotia.

The only exception is Sable Island Reserve, which was left out because it remains unclear if Mi’kmaq traditionally frequented and used Sable Island, Jonathan Sheppard, says. Sheppard is superintendent of Kejimkujik National Park and National Historic Site, one of the locations covered by the arrangement. Discussions about the governance and management of Sable Island are ongoing between Parks Canada and the Mi’kmaq.

The choice to create a province-wide agreement, rather than one focused on individual lands, was largely based on the Mi’kmaw preference for a collective approach because the Mi’kmaw communities in Nova Scotia operate as one unified political group, Sheppard says.

“[It was] really important for the ideas associated with self-governance and self-determination that this is a pan-Nova Scotia initiative, because it is ultimately about a nation-to-nation relationship and the nation-to-nation decision-making governance structure,” he says.

A shared vision 

Fundamentally, the arrangement is a framework to formalize the modern-day relationship while recognizing and implementing the Peace and Friendship Treaties, signed in the 1700s between the Crown and east-coast Indigenous communities.

 “This was not about negotiating rights and it was not about creating rights or extinguishing rights,” Sheppard says. “It was really about implementing rights originating from those original Peace and Friendship Treaties.”

In practice, the framework will be guided by a co-management board that will be made up of an equal number of Parks Canada and Mi’kmaw representatives. There will also be technical committees made up of Knowledge Holders, Elders and harvesters focused on specific topics, including language, culture and heritage; archeology; natural resource stewardship and harvesting; and economic opportunities.

While exact details will be developed over the coming months, the arrangement will include opportunities for practices on the land, including in protected heritage places. This will allow for practices such as ceremonies, Indigenous-led conservation activities and place-based learning and knowledge sharing.

The 10-year agreement has an option to extend or renew, although the Mi’kmaq are free to opt out at any point if they are dissatisfied. 

“ It was really clear to Parks Canada that there was a lot of overlap in vision about land stewardship, and that formed the basis for the agreement,” Sheppard says.

The Mi’kmaw concept of Netukulimk teaches about the respectful use of resources and only taking what you need from the land. It’s one of the principles Sheppard says aligns with Parks Canada’s vision for ecological integrity and preservation. Another is Msit No’kmaq, which suggests that all living beings are sacred and interconnected.

Etuaptmumk, or two-eyed seeing, is the concept at the very core of this new partnership, according to Lindsay Marshall, the Mi’kmaq relations advisor for the Cape Breton Field Unit for Parks Canada and a former chief of Potlotek First Nation.

Coined by Mi’kmaw Elder Albert Marshall, it means “looking at something with your western eye, and also with your Indigenous eye to come up with something truly beautiful and unique, and to understand it more,” he says. It is about combining both wisdoms to create a more holistic, in-depth approach. 

While the timeline to establish this arrangement was long, Marshall says it was the Mi’kmaq who set the pace, not the government. This required patience from Parks Canada at times, patience that helped demonstrate respect. So far, Sheppard says, the public response has been positive.

“ I’m really proud of the way the approach has been at the speed of the communities and not rushing, not being forceful in any way,” Marshall says. “That shows understanding and appreciation for culture.”

For First Nations in other provinces who may want to develop their own arrangements, Marshall suggests a similar strategy: go slow and build a real relationship before rushing into anything. 

And to federal agencies that may want to build partnerships with Indigenous communities, Marshall stresses the importance of doing the homework first. 

“Before you even set foot in the community, you should learn about the community,” he says. “You go at [their] speed and you approach with respect.”

Heal the people, heal the land 

For Clifford Paul, the moose management co-ordinator for the Unama’ki Institute of Natural Resources, this new arrangement is an opportunity for true healing among the Mi’kmaq.

“The Mi’kmaq language hasn’t been spoken in these areas in a long time,” Paul says. “The language belongs there. Our people belong there.”

It is also a chance to draw on Indigenous wisdom to help heal the land at a time when the environment is in dire need of protection. The Mi’kmaq have a proven track record of helping to improve the ecosystems in Nova Scotia’s parks, Paul says. In recent years, for example, they reintroduced pine martens into the boreal forest and helped to rectify an overabundant moose population through harvesting.

While the latter project was highly controversial — both with people who oppose hunting and non-Indigenous hunters who opposed being excluded — Paul says the Mi’kmaq successfully demonstrated their ability to get the job done safely while providing positive social impacts to their communities.

Restoring the spiritual connection between the Mi’kmaq people and the land is another crucial part of this deal, Paul says. Although the arrangement is about resource management and economic opportunities, it is also about harvesting knowledge from these sacred lands after hundreds of years of severed access.

“ When we go to these places and do our storytelling, it widens the breadth and scope of our Traditional Knowledge,” he says. “ You heal the people by taking them back to the land.” 

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