Summary

• Urban forests cool city streets, sequester and store carbon and absorb stormwater runoff, among other benefits.
• But city trees face compounding stressors, from disease and pests to heat waves and droughts, which makes looking after them an intensive process.
• In Winnipeg, the municipal government has increased its efforts to nurture the urban forest, with a goal of growing canopy coverage to 24 per cent by 2065.

Only a handful of years ago, the outlook for Winnipeg’s iconic urban forest was grim. 

The ash and elm-dominated canopy, best known for its elegant boulevard archways, had fallen into the clutches of Dutch elm disease and a scourge of emerald ash borer beetles. The city was losing public trees far faster than they could be replaced, planting just one tree for every three removed, according to the city’s 2021 “State of the Urban Forest” report.

But the introduction of Winnipeg’s urban forest strategy in 2023 changed the trajectory. 

The comprehensive planning document laid out a 20-year path to restore forest health, grow the city’s picturesque tree canopy and minimize the risks to tree assets.  

In response, the city hired more forestry staff and increased the department’s spending from approximately $11 million (where it had hovered since 2016) to an average of more than $17 million between 2023 and 2025, according to a review of city budgets.

Results followed: Winnipeg had planted an average 2,500 public trees each year between 2018 and 2022. In the years since the urban forest strategy was finalized, it has planted more than 6,000 per year.

Since 2023, the city has replaced felled trees on public lands at about a one-to-one pace (though this does not account for trees on private property or in natural areas such as the Assiniboine forest or the city’s riverbanks). 

But planting alone does not guarantee Winnipeg will make progress toward the urban forest strategy’s ultimate goal: to grow the city’s tree canopy cover from 17 to 24 per cent by 2065. 

Young trees must survive heat waves, droughts, severe storms, pests and disease to reach maturity and deliver the full benefits of the urban canopy. 

How a municipality cares for its trees — especially under increasing climate pressures — is just as critical to forest health as planting.

Planting a tree is just the first step. Then comes the weekly watering and the hand-weeding

According to Dave Domke, Winnipeg’s manager of parks and open space, the city’s trees are managed by a mosaic of forest stewards. Trees in new neighbourhoods are planted and maintained by developers, while the city’s urban forestry crews are responsible for replacing felled trees on boulevards or in parks. 

Community groups, neighbourhood associations and volunteers also plant and care for smaller trees in natural areas. Typically, these trees are planted as seedlings.

Domke calls the bigger trees the city looks after “large, ornamental trees.” These trees leave the nurseries when they are between seven and 10 years old and their trunks have grown to a 60-millimetre diameter.

“They need to be a substantial size in order to withstand our snow,” Domke said in an interview. “It also gives a nice aesthetic and it’s quite a nice size to grow on into the future.” 

After planting, volunteer groups, developers and city staff are then responsible for two years of dedicated tree maintenance called the “establishment period.”

“When you remove a tree from the nursery, you’re leaving about 80 per cent of the roots in the ground. You’re trying to get the trees re-established as quickly as you can,” Domke said.

During this time, trees are watered, weeded, mulched and protected according to a detailed list laid out in the city’s tree-planting and maintenance specification. 

Crews are expected to water trees immediately upon planting, then every one to two weeks throughout the summer. Trees should be hand-weeded during this time, the specifications say, and supported with protection collars and stakes.

Domke said the city’s maintenance work has been successful. Newly planted trees on boulevards and in parks survive about 90 per cent of the time, he said, about on par with the city’s expectations. 

Smaller trees in natural areas have a much lower survival rate, between 50 and 80 per cent, because they face more environmental challenges, he noted. The city compensates for the higher mortality rate by over-planting trees in these areas.

“We’re dealing with living things here, and you’re not going to be 100 per cent successful,” he said.

A healthy urban tree cools city streets and sequesters carbon — and costs at least $1,000

Healthy and mature trees provide a variety of environmental, health and affordability benefits to communities. 

A robust tree canopy provides shade, which can cool city streets, reduce the risk of heat-related illness and reduce air conditioner use by up to 30 per cent, according to the urban forest strategy. Winnipeg’s forest also stores an estimated 500,000 tonnes of carbon and sequesters nearly 40,000 tonnes of carbon dioxide each year — roughly double the city’s annual emissions from building electricity. At the same time, the city’s trees scrub pollutants from the air and produce approximately 15,000 tonnes of oxygen annually. Trees also absorb stormwater runoff, reducing strain on sewer systems.

But these benefits don’t come without maintenance, according to the Green Municipal Fund, an endowment group that supports Canadian municipalities investing in sustainability projects, including urban forestry initiatives. 

“Trees should be considered valuable natural assets, and like all assets they require maintenance,” communications director Julie Smithers said in an email.

But unlike traditional, grey infrastructure, which has a peak value when it’s first installed and deteriorates over its lifetime, trees are least valuable when first planted, but mature into their peak value over a period of several decades. 

“Given that the benefits of trees grow with time, maximizing their health and life expectancy is essential,” Winnipeg’s urban forest strategy says. “Tree assets cost the most at the beginning and end of their life cycles (planting and removal), so extending their time in healthy maturity ensures the urban forest maximizes the return on investment in tree planting and maintenance.”

The strategy gives the example of a single linden tree planted on a Winnipeg street: the city pays for its planting and annual maintenance until its removal. If it lives a long life, the strategy says, it will produce enough benefits — including carbon storage, avoided runoff, energy savings and pollution scrubbing — to give the city a positive return on its investment. 

But if it dies before maturity and must be repeatedly replaced, that single linden tree can cost the city a net loss of $18,000 over 100 years. That figure doesn’t account for the lost opportunity costs of having a healthy, mature tree over the same time period.

Climate change makes maintenance more challenging. More frequent storms mean more pruning is necessary, and more frequent droughts and heat waves necessitate more watering — especially for young, vulnerable trees. 

While the city does not have exact figures outlining the cost to maintain a tree throughout its lifetime, Domke said the average public tree costs roughly $1,000 to plant and care for through the establishment period.

Winnipeg’s public tree inventory valued at up to $740 million

Winnipeg has used that $1,000 figure, called the replacement cost, as a baseline to define the value of its trees. The city’s 2018 asset management plan valued the public tree inventory at just $226 million, based on a replacement cost of $740 at the time.

“This replacement valuation did not account for the fact trees grow and their value increases with size, age and health,” the urban forest strategy noted. 

“Valuing trees based on their size and condition would provide a better indication of the true cost of replacing Winnipeg’s tree assets, and the cost avoided by investing in maintenance to maximize their safe useful life expectancy.”

The forestry strategy recommended valuing trees according to a diameter-based replacement system, which it already employed for trees removed for construction. Small trees, with diameters of less than 10 centimetres, are valued at $1,000, while larger trees must be appraised according to a standardized formula.

According to the strategy, this approach pegs the value of the city’s tree inventory between $683 million and $740 million — more than double the asset management plan’s previous assessment.

Cities across Canada are employing tree appraisals and other natural asset valuation systems to better account for the benefits of urban forests, according to Tree Canada, a national rural and urban forestry non-profit. 

Using remote sensing and mapping technologies, as well as on-the-ground sampling, cities are better able to quantify the ecological and economic benefits of the forest canopy, Tree Canada notes in its urban forestry guide. 

These valuations make it easier for municipalities to measure the return on investment in tree maintenance.

In 2014, TD Economics estimated the ecological and economic value of forests in Toronto, Vancouver, Halifax and Montreal, and found every dollar invested in maintenance generated between $1.88 and $12.70 in benefits. 

A similar valuation strategy is on the horizon in Winnipeg, Domke said. The city is planning a flyover to analyze the tree canopy cover and support a more robust quantification of the forest’s value. 

“We all know they look good and are beautiful, but how much carbon sequestration are they undertaking? How much of the stormwater sewer management do they contribute to? What oxygen production is coming out?” Domke said. 

“These are the kinds of things that other cities have started to quantify, and Winnipeg is now on the road to doing that.”

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.

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Summary

• On May 27, Canada announced an agreement to supply Germany with one million tonnes of liquefied natural gas, or LNG, annually beginning in the early 2030s.
• The federal government says the deal will help Canada reduce its dependence on the U.S. market as trade relations grow more uncertain under President Donald Trump.
• Climate experts say the deal raises questions about the long-term costs of expanding fossil fuel exports.

Last week, the Canadian government celebrated a deal with Germany to supply the European country with one million tonnes of liquefied natural gas (LNG) per year, starting in the early 2030s. The agreement — essentially a handshake deal, yet to be finalized — is part of a broader federal scheme encouraging investment in major industrial developments across the country.

Natural gas is a fossil fuel mostly composed of methane, a potent greenhouse gas and major contributor to global climate change. Fossil fuels account for around 68 per cent of global greenhouse gas emissions and nearly 90 per cent of all carbon dioxide emissions. The more greenhouse gases released into the atmosphere, the bigger the effect on global warming and the stronger the impacts felt on the ground. More frequent and intense extreme weather is one significant effect, and one that Canada is already experiencing.

In 2023, smoke from wildfires in Canada caused more than 80,000 premature deaths across the globe. Of those who died, more than 20,000 lived in Europe. That same year, nine-year-old Carter Vigh died in B.C. of an asthma attack aggravated by wildfire smoke.

The following year, fires burned through Jasper, Alta., killing a young firefighter named Morgan Kitchen and causing more than $880 million in insured damages. According to the Insurance Bureau of Canada, nationwide losses related to “severe weather” surpassed $9.4 billion in 2024, including $3 billion in a single hour during a hailstorm in Calgary.

In 2025, around 85 per cent of Canada experienced severe drought conditions. Meanwhile, a storm surge flooded the northern community of Tuktoyaktuk, N.W.T., with water levels rising to the highest ever recorded in the region at 2.62 metres.

Canada touts the new export agreement with Germany as a necessary move to diversify the economy by decreasing its reliance on trade with the United States, which has become increasingly volatile since the re-election of President Donald Trump.

“We must build projects that strengthen our economy, that diversify our supply chains and enhance our energy sovereignty as well as expand our exports beyond a single market,” Canada’s Minister of Energy and Natural Resources Tim Hodgson said on May 27.

When asked how Canada squares its stated climate commitments with support for expansion of fossil fuel production, a spokesperson with Natural Resources Canada said LNG produced in Canada is “widely recognized for its low emissions intensity compared to global averages.”

Canadian LNG is often positioned as a “transition fuel” helping countries reduce reliance on other energy sources, like coal. But many European countries, including Germany, have been importing LNG as a means to replace Russian gas since the Ukraine war began in 2022. The current U.S.-Israel war on Iran has put further pressure on countries with gas contracts in the Middle East.  

Environmental economist Dave Sawyer said the new agreement clearly shows how the narrative of Canadian LNG as a climate solution is “patently false.”

“This notion that LNG is reducing global emissions is blown out of the water by this German deal,” he told The Narwhal. “This LNG is not being used to displace coal. There’s no incremental emission benefit from Canadian LNG in this deal.”

‘Just be honest’

Increasing long-term reliance on fossil fuel exports is also a risky economic maneuver, according to Steven Haig, policy advisor with the International Institute for Sustainable Development.

“The costs of climate change are being felt now and we shouldn’t lose sight of that,” Haig told The Narwhal in an interview. “They will get worse as time goes on and emissions increase — but this is a problem today, not just a problem for the future.”

Wildfires, droughts and floods are among the many increasing climate impacts claiming lives and diverting government funds to emergency response and health services. These costs will need to be met by higher taxes, placing a heavier burden on lower-income households.

A recent New York University School of Law cost-benefit analysis of U.S. LNG exports found that “climate damages greatly exceed economic benefits.” The analysis showed that a conservative accounting of damages — described in the report as “likely underestimates” — are roughly double the economic benefits. In other words, LNG exports cost twice as much as the revenues they earn.

“These are costs that are expected to increase as temperatures continue to rise, meaning that reducing carbon pollution today is an economic imperative,” Haig said. “Good climate policy is good economic policy and the two shouldn’t be considered [in] opposition.”

In 2022, Sawyer worked on a Canadian Climate Institute report analyzing the macroeconomic effects of climate impacts. The report detailed how the federal and provincial governments are increasingly forced to allocate public funds to respond to climate disasters and how this impacts the cost of living for all Canadians.

“Replacing and repairing damaged infrastructure, back-stopping weather-related disaster costs and funding increased health care needs all place greater demands on government budgets,” the report noted. 

Sawyer said LNG exports are like an ATM.

“It is a profitable business — it generates a lot of money for some,” he said. “But it is climate damaging and there are costs associated with climate damages. Just be honest about it.”

Canada should not subsidize fossil fuel exports: experts 

The new agreement with Germany’s state-owned energy importer is the third supply deal secured by Ksi Lisims LNG, a provincially and federally approved floating export facility in British Columbia. 

Ksi Lisims aims to produce up to 12 million tonnes of LNG annually, sourcing its gas from northeast B.C. and transporting it through an 800-kilometre pipeline. Construction has not started on the facility and its owners have not reached a final investment decision, the crucial last step before companies decide to spend the vast sums required to build a major project.

“This deal with Germany … only covers around eight per cent of Ksi Lisims’ projected annual export capacity, so that’s not a lot of LNG that we’re talking about,” Haig noted. “The broader market trends still point to long-term risks for high-cost LNG exporters like Canada.”

The deal also isn’t really a deal — yet. So far, the parties have signed a non-binding preliminary document known as a “heads of agreement.” An official purchase agreement would need to be finalized before Ksi Lisims could use it to attract investment.

Ksi Lisims is owned by Texas-based Western LNG, in partnership with the Nisga’a Lisims Government and a coalition of gas producers called Rockies LNG Partners. The owners have already signed deals with Shell and TotalEnergies to provide each with two million tonnes of LNG per year. 

Canada has long been a major producer of oil and gas, mainly exporting to the U.S. via a network of cross-border pipelines, but the country’s economy is not reliant on the sector like some petrostates. According to the Canadian Association of Petroleum Producers, the industry accounts for about 3.8 per cent of the country’s gross domestic product.

Canada’s ambitions to become a global player in liquefied natural gas exports were first realized last year, when LNG Canada sent its initial shipments of the fossil fuel across the Pacific Ocean to Asia. Construction of LNG Canada was heavily subsidized by the B.C. and federal governments.

The federal government’s public investment agency, the Canada Infrastructure Bank, is considering providing new financial support for projects like Ksi Lisims LNG, according to recent reporting by the Globe and Mail.

“The government of Canada should not be subsidizing oil and gas development — they can bet their own money,” Sawyer said. “The government’s job is to put the safeguards in place, not spend money.”

Haig agreed.

“If Canada’s LNG projects can’t stand on their own two feet, then public dollars should not prop them up,” he said. “These are highly risky investments and public subsidies effectively shift that risk away from private corporations onto Canadian taxpayers.”

“[That], in turn, makes it more likely that projects go ahead even if they may lose money in the long run, becoming stranded assets that may need to be cleaned up with public funds.”

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Wearing regalia bearing the raven crests of his mother’s clan, S’mooygyet (Chief) Algax’m Hax, Murray Smith, of the Gitwilgyoots Tribe, shared where he comes from. Sharing his lineage is a necessary precursor to welcoming visitors to his lands, he explained.

“When I get up here to speak, I have to tell you who I really am,” he told a group gathered in Prince Rupert, B.C., earlier this month. “My grandfather is Haida. My mother’s mother was Ts’msyen from Lax Kw’alaams.”

“There’s a word in my language called sg̱an,” he continued. “Sg̱an is a welcome mat made out of cedar and they place it at the bow of a canoe. When the Chief steps off, he doesn’t step on the ground, he steps on the welcome mat.”

“Chiefs, matriarchs, high-ranking women, young people that are here: the welcome mat is out,” he declared.

Algax’m Hax is a Hereditary Chief of the Gitwilgyoots, one of the Nine Allied Tribes of Lax Kw’alaams. Ten years ago, he and other chiefs signed the landmark Lelu Island Declaration, placing vital salmon habitat in the Skeena River estuary under the protection of Indigenous laws. In solidarity with the Gitwilgyoots Chiefs, leaders of First Nations and elected officials from across the region signed onto the declaration, which extended an invitation to all to join in “defending this unique and precious place and to protect it for all time.”

At the time, the estuary — one of the most productive and ecologically important salmon habitats in B.C. — was threatened by the looming prospect of a major liquefied natural gas (LNG) export terminal, which was to be built on the island. The following year, Malaysian oil and gas giant Petronas cancelled its plans to build the Pacific Northwest LNG facility. A totem pole was raised on the island, to keep watch and assert stewardship. Two years later, the Prince Rupert Port Authority imposed a development moratorium over the sensitive area.

This spring, as juvenile salmon migrated from the creeks and rivers out to the ocean, Indigenous leaders and allies met to mark the anniversary of the declaration and talk about the future of salmon stewardship in the estuary and watershed. Algax’m Hax spoke to the importance of salmon and expressed solidarity with all who give of themselves to protect the species.

“I see you all here fighting for one thing, and that’s for our salmon,” he said. “So goes the salmon, so do we.”

He looked around the room and said he was called to speak by his fellow chief, Yahaan, who wasn’t able to attend the gathering. He said he phoned Yahaan the night before the event and asked what he should say.

“He said, ‘You’ll find your words,’ ” Algax’m Hax recounted. “It’s easy when I sit amongst people that care, people that dedicate themselves to the wellness of our salmon here on the North Coast, on the coast altogether. I take my hat off to you.”

Salmon connect ‘communities, cultures and generations’

The protection of Lelu Island — and Flora and Agnew Banks, the delicate estuarine habitat around the island — took years of dedication and sacrifice by Indigenous and non-Indigenous leaders and community members. 

Loggers, commercial fishers, scientists, politicians and more agreed building a massive LNG facility in the sensitive estuary would be a catastrophic mistake with far-reaching impacts on the livelihoods and cultures of communities across the region. Weaving Indigenous science and academic research, allyship and land defence, people from across the Skeena watershed and beyond came together to stand up for the salmon, sending ripples far and wide.

“Salmon do something extraordinary,” Julia Hill, executive director of SkeenaWild, said at the two-day event. “They connect ecosystems … communities, cultures and generations. They’re part of the social, cultural and economic fabric of this place.”

In the years since the declaration was signed, Indigenous and non-Indigenous salmon stewardship and science has been ongoing throughout the Skeena watershed. At the gathering, representatives from Fisheries and Oceans Canada presented alongside environmental organizations, academics and First Nations. 

Jonathan Moore, director of the Salmon Watersheds Lab at Simon Fraser University, said the reason the species is able to thrive today is because of this unity and the continuity of stewardship.

“Right now, as we gather, literally hundreds of millions of young salmon are migrating down from throughout the Skeena, potentially hundreds of kilometres away, and they’re all coming down just around the corner and they’re hitting the ocean,” he said, grinning. “It gives me chills, honestly, to think about that phenomenon that unfolds every year because of these intact ecosystems that have been stewarded for millennia.”

But while the protections of Lelu Island remain in place, wild salmon continue to face multiple threats. Many populations across the watershed are struggling. 

“This region is experiencing enormous pressure and rapid change, from climate change and warming waters to industrial expansion and growing global demand for resources,” Hill said. “At the same time, many communities here depend on resource-based economies. So the question isn’t development or no development. The question is how much, where and to whose benefit.”

That tension is rising amid talk about new pipelines from Alberta and the spectre of lifting the oil tanker moratorium on the North Coast. A slew of projects supported by the provincial and federal governments are putting increased pressure on already-impacted salmon habitat throughout the northwest. 

All of this is set against a backdrop of talk by the provincial government about amending or repealing B.C.’s Declaration on the Rights of Indigenous Peoples Act. It leads some to fear hard-won battles like the protection of Lelu Island could be undermined by an onslaught of new industrial developments that would provide little benefit to the communities who would pay the highest costs.

“We’re witnessing this backlash against Indigenous Rights, against Indigenous stewardship, against title to the land being recognized,” Naxginkw Tara Marsden, Wilp sustainability director with the Gitanyow Hereditary Chiefs, said. “We’re at a critical juncture for salmon stewardship and for the well-being of our communities.”

Marsden emphasized the intersection between rights and responsibilities.

“If we receive a full basket, we have to make sure we pass on a full basket,” she said. “So in my lifetime, if I see the salmon stocks decline to a point of extirpation, then I haven’t done my job for my kids, my grandkids.”

‘This impacts everybody’

For Grace Vickers, daughter of Andrea Vickers and revered carver Roy Henry Vickers, all conversations about stewardship and economy need to start from a shared baseline. Introducing herself as Heiltsuk belonging to the House of Walkus, she spoke about the importance of place-based knowledge.   

“What’s important today is what is sustaining us,” she said, during a youth panel at the gathering. “It’s the air we breathe, it’s the fish we eat and it’s the water we drink.”

Vickers and four other young women — Nasya Moore, Oasis Cleveland, Drew Harris and Kayla Mitchell — shared what it’s like being young at a time when so much is changing. They spoke about cultural disconnection and reconnection and the strength and restorative value of spending time on the land, harvesting and processing fish.

Harris, who is Wet’suwet’en and Gitxsan, said she sees how land protections, human rights and stewardship of the likes of salmon can become siloed.

“Like: there’s the fish, there’s the land, there’s the people, there’s the health,” she said. “But it’s all connected. We can’t just silo these things and differentiate them and not talk about it together. Just seeing the different connections and looking from a different perspective can really help you understand the full picture and how to treat that problem.”

She said acknowledging the scale of the problems facing communities can be unifying and called out fossil fuel expansions as a global issue.

“Everywhere we go, we meet the youth and they all have their own projects that they’re fighting,” she said. “It’s sad but it connects us all together.”

“This fight isn’t just for the Indigenous people,” she added. “This impacts everybody.”

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Summary

• The federal government will offer tax credits to companies that capture carbon pollution and use it to extract more oil.
• That process is called enhanced oil recovery, and it involves injecting carbon dioxide deep underground to push more oil to the surface.
• Critics say subsidizing enhanced oil recovery operations is counterproductive. It does stop some carbon dioxide from escaping into the atmosphere, but it also enables the production of more carbon-emitting fossil fuels.

Canada is planning to give financial incentives to companies that capture carbon dioxide and use it to produce more oil. The technique, called enhanced oil recovery, was formerly barred from receiving federal tax credits. 

Huh? Enhanced oil recovery? You’d be excused for scratching your head.

The technique uses carbon dioxide to pump more oil (we’ll get into it below) — and is controversial. Can you reduce emissions by pumping more oil? 

But the government’s ban on subsidies for enhanced oil recovery projects was reversed in dramatic fashion last year, first in a deal with Alberta that resulted in cabinet minister Steven Guilbeault resigning.

The government then solidified the change across the country in its latest economic update.

So what is enhanced oil recovery and what are its impacts on emissions and on government finances?

Here’s a primer.

Back up, what’s carbon capture, utilization and storage?

Industries emit a lot of carbon dioxide. Too much. Governments have tried to incentivize companies to reduce the amount of carbon pollution they release into the atmosphere — where it traps heat and contributes to climate-driven problems like increased wildfire, hurricanes, droughts and more.

One strategy is to capture the carbon pollution rather than release it up into the sky, then either store it (storage) or use it to make other things (utilization). When it’s stored, it’s most often injected deep underground.

There are two options in this scenario: one, it can be stored underground, plain and simple. Buried and forgotten.

The second is that you use the carbon dioxide to get more oil out of the ground, then store it. That’s what’s known as enhanced oil recovery — in essence, injecting carbon dioxide into a well so you can get more oil. Globally, it’s by far the most common of the two.

A 2022 report found nearly three-quarters of captured carbon pollution around the world is used to extract more oil.

How does enhanced oil recovery work?

Enhanced oil recovery can involve pumping anything from water to steam to gas deep into the ground to increase pressure in an underground oil reservoir. The goal? To force more oil out of a well. 

But in this instance, we’re talking specifically about using captured carbon dioxide as the pressure builder, often alongside water.

A company will either capture carbon pollution, or purchase it from another source, and then inject it deep underground to push more oil to the surface. Most of that carbon pollution will then remain trapped underground.

A well-designed system will capture emissions from the enhanced oil recovery operation and reinject them back into the reservoir, creating a closed loop, but not all systems will capture all emissions.

Sounds smart, what’s up?

The process can significantly prolong the lifespan of a fossil fuel reservoir, so it makes sense if the goal is to increase or extend production. 

It also creates a bigger market for captured emissions, further incentivizing companies to capture carbon pollution rather than release it into the atmosphere. 

But the issue is that enhanced oil recovery takes carbon dioxide, ostensibly captured to reduce emissions, and uses it to pull more carbon-emitting fossil fuels from the ground.

Determining whether there is a net reduction in emissions from this process is complicated and depends on a lot of factors — including how much traditional production is displaced by enhanced oil recovery, how much carbon is actually stored underground, the impact on prices and demand, how much carbon is produced while recovering oil, the type of oil produced and the lifecycle of the fuel that is produced.

Sound complicated? It is.

Research suggests the process can achieve reductions in per-barrel emissions, commonly referred to as emissions intensity.

On the other hand, enhanced oil recovery produces more carbon pollution than simply capturing and storing emissions permanently underground.

Traditionally, enhanced oil recovery used carbon dioxide that was naturally occurring and already stored underground, but newer methods involve using captured emissions — a critical distinction when discussing the potential of any emissions reductions. 

As one 2025 peer-reviewed meta-analysis of enhanced oil recovery research dryly suggested, “the extent to which [carbon capture and utilization] projects that store captured [carbon dioxide] in oil reservoirs support achieving [greenhouse gas] emissions targets is debated.” 

That study found analyses of the life-cycle emissions of enhanced oil recovery vary greatly — all the way from increasing emissions to reducing them.

So, why are we talking about this?

The previous Liberal government announced tax credits for carbon capture and utilization projects, significantly reducing costs for the companies building them. Projects are typically expensive to build and the government wanted any and all emissions reductions to move ahead. 

It excluded enhanced oil recovery, arguing it was counterproductive to reducing overall emissions and the government’s goal to move toward a net-zero economy.

The Liberals under Prime Minister Mark Carney, however, reversed that decision and announced enhanced oil recovery could receive tax credits, first in a November memorandum of understanding with Alberta regarding a new pipeline, and then again in its latest economic update. Industry cheered the decision, while those concerned with emissions cried foul.

Under Carney’s new rules, a project will have to permanently store 95 per cent of the carbon dioxide used to pump more oil be eligible for tax credits. 

In Alberta, the government already provides tax credits for enhanced oil recovery operations. That program does not include the need to capture a minimum amount of carbon in order to qualify.

Critics call these credits a fossil fuel subsidy. Companies who receive the money from the federal and provincial governments do not. Therein lies the debate.

What will this cost taxpayers?

That will depend on how many producers meet the criteria set by the government.

In 2024, the Parliamentary Budget Office estimated the tax credit would cost the government $5.7 billion between 2022 and 2028 — but that was before enhanced oil recovery was added to the list of eligible projects. It’s unclear what the impact of that addition will be. 

There is one important distinction: the tax credits for enhanced oil recovery aren’t as lucrative as those for storage alone: the amount of money an oil project can recoup is half of what a company that simply stores carbon permanently underground can receive. 

For that reason, the federal government estimates credits for enhanced oil recovery might actually save some taxpayer dollars — $395 million over four years, starting in 2027, according to a federal Department of Finance official responding to questions from The Narwhal.

The official said the savings would come from companies deciding to store carbon for enhanced oil recovery rather than dedicated storage, and receive less public money for doing so.

While incentivizing enhanced oil recovery may represent a savings in terms of tax credits, the costs come from increased emissions and long-term impacts.

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When 27-year-old Kaitlyn Kitzan was a kid, farmland near her parents’ farm in southeast Saskatchewan cost about $400 an acre.

Today, in that same region, it’s almost ten times as valuable: $3,500 an acre.

Across Saskatchewan, farmland prices increased by an average of 11 per cent annually from 2005 to 2024.

As the value of farmland rises — alongside the costs of everything from fertilizer to fuel and more — Prairies farmers now face the harsh reality that the better business decision might be just to sell their land, rather than farm it. Alongside the pressures running capital-intensive businesses, climate change and volatile markets, the price of farmland is a major stressor for young farmers like Kitzan, who is trying to take over the family farm.

“We’ve seen [a] steady increase in farmland values to the point where [it has] outstripped the productive value of the land” Bill Prybylski, a veteran farmer from east-central Saskatchewan, says, noting high costs and low prices for crops aren’t helping.  

Financial woes aren’t only affecting small family farms. In April, Monette Farms — one of the largest privately owned farming operations in North America with hundreds of thousands of acres across Canada and the United States  — filed for creditor protection, illustrating the challenging financial situations agricultural operators of all sizes are facing.

“Why is land selling for more than its productive value? The only obvious answer would be speculative ownership,” Prybylski says.

Indeed, hedge funds, pensions and other investors have been interested in farmland in recent years, with farm groups like the Agricultural Producers Association of Saskatchewan (APAS) expressing concerns about foreign investment. Although provinces like Saskatchewan and Manitoba — which together are home to about half of Canada’s farmland — have regulations limiting farmland ownership primarily to Canadians and Canadian-controlled entities, the Saskatchewan government recently launched a review of its policies, saying it would take a closer look at farmland ownership, though it noted there is no evidence of foreign ownership of farmland in the province right now. Meanwhile, Ontario announced in April it will introduce legislation to limit foreign acquisition of farmland.

But that’s little comfort to those currently struggling with the price of farmland. “So much land is owned by people who aren’t farming it [themselves],” Kitzan says. “It is almost impossible to buy farmland from those people who are using it as an investment.”

Canada’s largest private farmland owner is an investor who owns 250,000 acres

There’s been a consistent, long-term shift in Canada toward fewer — and larger — farms. Between 2001 and 2021, the number of farms declined from about 250,000 to 190,000, with the average farm size increasing from 676 acres to 809 acres.

At the same time, investor interest in farmland has risen dramatically in recent decades. Investor ownership of farmland in Saskatchewan was negligible in 2002, but climbed to nearly one million acres by 2018 — almost 18 times the size of Saskatoon. An update to that research suggests the trend may be plateauing, but investors continue to be interested in farmland.

One of them is Robert Andjelic. He left a successful career in commercial real estate in Winnipeg in 2007 and turned his attention to Canadian farmland, an asset he believed was undervalued at the time, even though prices were already trending upward in the previous decade.

A few years later, he began purchasing Saskatchewan farmland at around $345 an acre. Today, land values in Saskatchewan have climbed to roughly $1,500 to $5,000 per acre, depending on the region. With more than 250,000 acres in his portfolio, primarily in Saskatchewan, Andjelic is considered Canada’s largest private farmland owner.

“I used to trade gold, silver, oil, other commodities. Today I have zero in anything else other than farmland. I’m 100 per cent invested in farmland.”

For Andjelic, there’s no doubt that Canadian farmland values will continue to rise. He sees farmland as a resilient, long-term, wealth-preserving investment — particularly during economic downturns.

“The world needs Canada and Canada’s production,” he says, adding food is not an optional consumer good.”

As the global population rises, so too does the demand for food. At the same time, farmland globally is becoming scarcer. Each year, an estimated 22 billion tonnes of fertile soil is lost to erosion, while millions more acres are degraded or converted to urban and industrial uses. 

As a result, there are simply fewer parcels of land available than there are buyers, Justin Shepherd, senior economist at Farm Credit Canada (FCC), says.

“Overall, it’s a really tight supply of land, and there’s been consistent and strong demand from producers looking to grow,” he says, adding there’s limited land for sale.

At the same time, advances in technology and larger equipment mean farmers can manage more acres with the same workforce, incentivizing them to keep expanding and increasing competition for land, which pushes prices higher, he says.

But that creates challenges in terms of access, he says, particularly for younger farmers trying to enter the market.

“We’ve looked at the affordability of farmland and recognize that we’re near historical records for many regions.”

And while Canadian farmland values have experienced growth periods before, all these recent factors have combined to create a longer and more sustained period of land price increases than at any other time in recent history.

A mega farm that wants to feed a billion people a day files for creditor protection

High land prices, and the financial challenges in agriculture, are creating a squeeze for farmers big and small. This was made even clearer in late April when Monette Farms — one of the largest private farming operations active in North America — filed for creditor protection under the Companies’ Creditors Arrangement Act.

The company reportedly farms approximately 475,000 acres of owned and leased land across Canada and the U.S. The business, a collection of companies that originated from a family farm in Swift Current, Sask., had a goal to “feed a billion people for a day.”

In a note to stakeholders, the company said it was attempting to restructure its debt after rising interest rates and mounting costs strained its finances.

In a court document, Darrel Monette, the head of Monette Farms, said “the real property alone had a valuation exceeding the value of the group’s consolidated liabilities,” suggesting land value alone is more than its total debts. The document states Monette Farms holds about $900 million in secured debt.

Though the company didn’t specifically cite farmland prices as a reason it was facing strain, Monette Farms’ situation drew significant attention from Canadian farmers, reflecting tensions that had been building for years. 

In light of this, many say it’s now critical to confront whether farmland values have outpaced what is financially sustainable to actually farm. Prybylski, who is also the president of APAS, says the current system not only limits expansion for young farmers like Kitzan, it also threatens the very future of the family farm. (Approximately 97 per cent of Canadian farm businesses are family-owned and operated.)

Prybylski welcomes the Saskatchewan government’s move in April to launch a comprehensive review of its farmland ownership rules, examining ownership verification, enforcement and transparency, particularly around corporate ownership.

“Whenever we’ve talked to farmers,” he says, ”the conversation always comes around to stories of foreign ownership.”

Many farmers believe farmland simply shouldn’t be an investment strategy. But Andjelic thinks concerns about a disconnect between profitability and land stewardship miss the mark. 

He argues the two are closely linked — and that long-term investor returns depend on how well the land is managed.

He says he only rents his land to farmers he considers leaders in soil and crop management, requiring them to demonstrate their practices through an application process. He says his team also regularly visits farms, reviewing crop rotations, soil practices and overall land management.

“Soil is both of our bread and butter,” he says. “We’re only as good as the soil and the way we treat that soil. If somebody is mining the land, I don’t care if he pays me two times more than what the market is, he’s not going to get it.”

Eight billion people need to eat

The growth in Saskatchewan farmland values has begun to slow in recent years, but prices still increased by 9.4 per cent in 2025. At the same time, interest rates, farm profitability and regional climate pressures are predicted to play a larger role in affecting farmers’ bottom lines.

Ted Cawkwell, a farmland realtor based in Saskatoon, says some drought-affected areas — particularly in the southwest — have been under pressure as crops have failed or brought in low prices.

“Some of those areas… have had no crop for five, six years,” he says. “Grain prices are low and input costs are high and machinery costs are high. It’s tricky.”

As a result, real estate listings for farmland are increasing in some regions and taking longer to sell, not because values have dropped sharply, but, Cawkwell says, because buyers lack cash.

“The listings that are there just aren’t selling because the farmers don’t have cash,” he says.

But Cawkwell remains optimistic about the long-term outlook, pointing to the big picture.

“We have eight billion people … and people need to eat. You can do without the new house, you can do without the new shoes, you can do without the new car — but you can’t do without food.”

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Summary

• Manitoba is one of Canada’s sunniest provinces, but it hasn’t prioritized solar power as an electricity source.
• Instead, the province relies on hydroelectricity for almost all of its energy needs. But as electricity demand increases and droughts make hydroelectricity less reliable, Manitoba Hydro has warned capacity could run out as soon as 2030.
• The province argues solar power isn’t well suited to meet Manitoba’s energy demands, which spike in the cold, dark winters. So, it’s prioritizing fossil fuels instead.

In the early 1970s, licence plates were stamped with the slogan “Sunny Manitoba” — a nod to long summer days, crisp blue winter skies and frequent sun dogs reflecting off of blinding white snow. While the slogan later changed, Manitoba’s ranking as Canada’s second-sunniest province has not. 

Despite that sunny reputation, solar power — one of the most developed renewable energy sources — makes up a small fraction of the province’s electricity grid.  

“It’s extremely marginal, especially when you compare to other jurisdictions like Alberta and Saskatchewan,” James Wilt, policy development manager at Climate Action Team Manitoba, said in an interview.

Manitoba boasts a predominantly emissions-free grid, with 97 per cent of its power generated by a network of hydroelectric dams. But the provincial utility, Manitoba Hydro, has forecasted that its once-abundant renewable energy source will soon fall short. There is growing demand for power amid the electrification of sectors like transportation and heating and the rapidly growing interest in developing power-hungry data centres. Combined with more unpredictable water levels owing to climate factors like extreme drought, it’s all prompted the utility to warn that capacity could run out as soon as 2030.

Manitoba’s plight is not unique: power producers around the world are navigating pressures to keep pace with skyrocketing demand. The International Energy Agency’s most recent world energy outlook states “the age of electricity is here,” and demand will continue to grow “much faster than overall energy use” in the coming decade. It predicts renewables will grow “faster than any other major energy source” in that time, led by solar power. 

But not in Manitoba. The province’s near-term energy plans include building new wind farms and natural gas-power; utility-scale solar isn’t on the table, with Manitoba Hydro going as far as saying solar power is “opposite to Manitoba’s energy needs.”

Others, however, believe more investment in solar infrastructure and government incentives could help build a more resilient grid without resorting to fossil fuels.

Welcome to the sunbelt: Manitoba is second only to Saskatchewan for sun

Solar power technology has been on the market since the 1980s, and in that time has become less expensive and more efficient, establishing solar power among the most accessible renewable resources. 

“The thing with solar is that it really does work effectively anywhere,” Wilt said. “Of course, there are differences in the number of hours of sunlight … but even if it’s farther north or on a rooftop that isn’t perfectly angled, it can still generate a really significant amount.” 

Some systems are solar thermal, meaning the sun is used to heat either water or air (think hot water tanks or air-source heat pumps). Solar-powered electricity, however, is generated by solar photovoltaic systems, which use specialized panels to convert sunlight into an electric current.

Photovoltaic systems are typically classed as either distributed, meaning they are installed on individual homes, businesses and farms to generate power for that property, or utility-scale, which refers to larger solar farms that send electricity directly to the grid.

These systems share the same central principle: when the sun is shining, they’re generating power — regardless of the season or the temperature. 

And that’s where Manitoba has an advantage: according to an analysis by Natural Resources Canada, the province (particularly the southern region) has some of the greatest solar power potential in the country. 

Winnipeg ranked fourth on the Canada Energy Regulator’s 2018 list of major city solar potential, behind only Regina, Saskatoon and Calgary, with the potential to generate an average of 6.6 kilowatt-hours of electricity per square metre, per month. Manitoba ranked second among provinces, behind only Saskatchewan.

A 2020 Manitoba Hydro study of properties with existing solar electricity systems found panels produced power for about eight hours per day in the winter and more than 14 hours per day in the summer months.

“We are in the sun belt of Canada,” Lorena Mitchell, lead designer at solar power installation and education company Evolve Energy, said in an interview. “We do get an awful lot of sunlight hours here in Manitoba.”

Solar power makes up 0.005 per cent of Manitoba’s electricity

Manitoba’s ranking at the top of the solar-power-potential charts hasn’t translated into an abundance of solar energy. 

As of December 2024, the most recent numbers available, Manitoba’s current solar capacity of 41 megawatts is exactly middle of the road among Canadian provinces and territories. All of that capacity comes from distributed sources, such as homes, businesses and farms, Manitoba Hydro communications director, Scott Powell, said in an interview. 

All told, solar power makes up 0.005 per cent of Manitoba’s energy mix.

“Solar power is definitely part of the energy mix in Manitoba, but what we’ve seen is it’s more so put on very localized production,” Alexander Lavoie, board chair of the Manitoba Sustainable Energy Association, a non-profit advocacy organization, said in an interview.

The gap is more stark when compared to neighbouring provinces Saskatchewan (108 megawatts) and Ontario, which ranks first with over 2,500 megawatts. Alberta — another Prairie sun-belt province — ranks second with nearly 2,300 megawatts, though a less-than-favourable political climate has seen investment interest in solar energy decline. South of the border, Minnesota has more than 3,300 megawatts of installed solar capacity, which accounts for about six per cent of the state’s electricity.

Part of the discrepancy stems from Manitoba’s unique regulatory environment, Lavoie said. In some jurisdictions, like Alberta, private energy companies can develop large-scale solar resources, whereas Manitoba’s public utility model means any major infrastructure investments need approval from an external body — the Public Utilities Board.

Manitoba offers the second-cheapest power in the country (behind Quebec) and must get approval from the utilities board to raise electricity rates, which can constrain capital expenditures.

“Low electricity rates in Manitoba make the investments probably a little bit more difficult to manage,” Lavoie said. “[For] utilities of scale, there may be other opportunities that provide a better [return on investment].”

Still, solar generation has boomed in Canada, from 0.1 terawatt-hours in 2010 to nearly five terawatt-hours in 2023 — about one per cent of the national energy mix, or enough to power 195,000 homes for a year. The energy regulator predicts that share will keep growing, reaching 13 terawatt-hours by 2040.

Quebec, which operates a similar electrical grid makeup to Manitoba, plans to install three gigawatts of solar power by 2035 and an additional 300 megawatts of distributed solar in the next 10 years. New Brunswick will install a 10-megawatt solar project co-owned by Tobique First Nation this year, while Prince Edward Island’s solar incentive program was paused in 2025 because it was oversubscribed.

And while Manitoba has seen its share of solar growth, it is not betting on the sun to meet its future energy needs.

Manitoba Hydro says long, dark nights and snow make solar panels less desirable

Typically, Manitoba Hydro sees the greatest demand for electricity in the early mornings and late evenings of cold winter days, and that peak winter demand is a big part of why Manitoba has hesitated to invest in solar power.

“As much of the system’s winter peak load occurs during the non-daylight hours, solar provides little to no energy when it is needed most,” Manitoba Hydro states in its 2025 integrated resource plan.

The plan, which is intended to guide the utility through the next 10 years of the energy transition, lists six resources it believes will be feasible to develop in that time — existing and expanded energy efficiency programs, wind power, short-term battery storage, natural gas and upgrading the existing hydroelectric infrastructure. Solar isn’t included.

In a slide outlining the rationale for leaving utility-scale solar off the table, Manitoba Hydro notes that while it comes with the advantages of low costs, low maintenance, negligible emissions and easy scalability, solar power “provides zero accredited winter capacity in Manitoba,” adding solar panels are “often covered in snow,” and their “energy production profile does not pair well with Manitoba Hydro’s demand.”

Instead, the utility is prioritizing new generation options that can help address a forecasted shortage of more than 250 megawatts during those peak times. 

“The [integrated resource plan] is really about growing our capacity and, at the same time, ensuring we can provide the electricity when we need it most,” Powell said. “At a utility scale, other sources of energy are typically more available and effective based on our load curve.” 

To Wilt, at the Climate Action Team, this approach to assessing the value of solar power “takes a very narrow-minded focus on meeting demand without thinking about the system holistically.”

Battery-storage technology has evolved alongside intermittent resources like solar and wind power, and could allow solar energy to be stored and used when it’s needed most, he said. 

While Manitoba Hydro plans to run a five-megawatt battery-storage pilot in the coming years, according to the integrated resource plan, Wilt pointed out Manitoba already has a power-storage advantage.

The hydro-powered grid is backstopped by Lake Winnipeg, which has been engineered to serve as a reservoir, with the utility able to control flow to its generators. In other words, the lake essentially serves as a battery that can complement other renewable power sources. 

From Manitoba Hydro’s perspective, while the reservoir will be used to help backstop upcoming wind resources, “you can only backstop it so far,” Powell said. 

Wilt said the Climate Action Team does not want to downplay the “difficult position” Manitoba Hydro is in when it comes to managing its reservoirs and generation capacity in the face of increased pressures.

“But we would argue that a great way to shore up and prevent overutilization of potentially compromised reservoirs is by adding the lowest cost generation to the mix during the summer,” he said. 

“We think that there should be tons of solar put on the grid for the summer, tons of wind put on the grid for the winter — which is when it’s most effective — and have battery storage which can help smooth out the intermittency. Having all of these in place will help keep more water behind the reservoirs.”

Manitoba Hydro solar pilot project was a success — but wasn’t renewed

A decade ago, the forecast for solar power in Manitoba was sunny. 

With solar photovoltaic power gaining popularity, the provincial utility launched a pilot project in 2016 offering customers a $1-per-watt incentive to install solar panels on their properties. This rebate was considered among the best in the country at the time, and covered up to one-third of the cost of installations. 

Mitchell, at Evolve Energy, has worked in the solar energy space for more than 20 years. She noticed Manitobans interest in solar started to spark in 2013, “then they launched the rebate program and that’s what really kicked it off.”

The pilot program was a success, generating 2.6 megawatts of new solar generation capacity and diverting approximately 3.5 gigawatt hours of energy from the provincial grid each year, about equivalent to the power use of 137 homes.

“By all accounts, Hydro was just completely overwhelmed by the number of applicants,” Wilt said. 

(At Hydro, Powell said the pilot was “very well received at the time.”)

Customers were set up with a bi-directional meter that allowed each property to both import and export power to and from the hydroelectric grid. This kind of grid-connected system is common for residential and small commercial solar generation: when the sun is shining, the property draws power from the solar array and sells whatever it doesn’t need back to the grid. When it’s dark, the system can still draw power from the grid as normal.

Excess power is compensated using either net-metering or net-billing. Net-metering — used in nine of 13 provinces and territories — credits the property owner for each kilowatt-hour of energy they send to the grid, charging users only for the difference between the power they use and the power they contribute. 

Net-billing, on the other hand, effectively pays distributed solar producers an electricity rate for each kilowatt-hour sent to the grid. Manitoba, Saskatchewan, Alberta and British Columbia use net-billing systems, with varying rates across the jurisdictions. 

Under Manitoba’s solar pilot project, the excess energy rate, as it’s called, was on par with electricity rates charged by the utility. 

When the pilot project ended, the solar landscape in Manitoba changed.

Some contractors that had come to the province looking to cash in on the solar boom vanished; several customers were left scrambling to finish setting up their systems before the incentive program ceased. 

“When it ended, the whole local industry collapsed,” Wilt said. 

The responsibility for doling out future solar power incentives shifted to then-newly formed Crown corporation, Efficiency Manitoba, which is tasked with administering initiatives to help Manitoba reduce its electricity and natural gas consumption. The new program, launched in 2022, offered a $0.50-per-watt incentive for residential installations, up to $5,000, and $0.75 cents for farm or business installations. It also switched to an excess energy rate set by Manitoba Hydro that “reflects the current market value” of electricity.

“Net-billing appropriately recognizes the value of that excess energy when it’s sold back on the grid,” Powell said. “Net-metering would pay customers at a rate that incorporates the full cost to deliver electricity to residential customers. Solar customers don’t have to absorb that cost, so it wouldn’t be appropriate to pay that full rate.” 

That price — which is established each spring — has fluctuated widely in the years since. In 2025, it was just over four cents per kilowatt-hour, in 2021, it reached a low of 2.4 cents. This year, it’s just over seven. 

“It can certainly provide uncertainty for potential investors and developers,” Lavoie said.

According to Jana Brunel, manager of strategic initiatives at Efficiency Manitoba, the program has seen “steady uptake,” with 750 installations to this point. Manitoba’s cheap and predominantly low-emissions energy, however, can limit the uptake when compared to other jurisdictions.

“We have low energy rates, which make the payback of some investments different,” Brunel said in an interview. 

Efficiency Manitoba also works with customers to match the size of their solar generation to their energy use, which results in less excess energy generation, Brunel explained. 

“If you can install solar to really reduce the energy you need to use from the grid … that’s where the biggest financial savings come,” she said. “That’s why our program is really geared at properly sizing a system not to have an abundance of excess energy being sent back to the grid.” 

Mitchell said the program has been “pretty good” for residential customers and “really amazing” for farms and commercial businesses. Those larger properties who receive higher excess energy rates, including those who are locked in to the on-par price, have seen a return on investment in their solar installations within six to nine years, she said.

“We’re seeing the uptick for them, finally, really happening this year,” Mitchell said.

For residential customers with smaller systems, Mitchell said her business designs systems to protect their investment from the fluctuating energy price.

“I try to caution them that this is what’s going to cause their investment to go up and down,” she said. “It’s like playing the stocks.”

Manitoba’s energy crunch looms, but solar adoption lags

In 2024, Efficiency Manitoba and Manitoba Hydro commissioned Dunsky Energy + Climate Advisors to outline a roadmap to help reduce peak demand through customer-facing initiatives such as energy-efficiency upgrades, heat-pump programs and distributed solar. 

The study found that by 2037, peak demand could shift towards the late afternoon, driven by factors like electric vehicle charging and improved energy efficiency. In such a scenario, distributed solar could reduce that demand by up to117 megawatts.

But it also found solar adoption “is not projected to approach levels observed in the past pilot program in the initial years of study unless lucrative incentives … are provided.”

“Despite continued global cost declines for solar [photovoltaic] systems, the decline in Manitoba’s solar [photovoltaic] market following the end of the pilot program, coupled with significant reductions in compensation for excess generation, is expected to reduce customer demand for the next several years,” the study said.

“However, as solar [photovoltaic] system costs continue to decline, adoption is projected to increase in the later years of the study.”

At Efficiency Manitoba, Brunel said solar power “certainly plays a role in helping reduce electricity consumption and energy consumption,” and its efficacy will improve in the long term as battery storage technology evolves and energy efficiency programs take root. 

“When solar [photovoltaic] systems can be paired with battery storage, that presents more of an opportunity to use the electricity,” Brunel said.

Manitoba Hydro isn’t closing the door either, Powell said. 

“We’re technology agnostic. If solar was the right answer for our system and our customers, that’s what we would be going with. But there are other technologies, other forms of energy, that offer better value for the system we have,” he said. 

“Could that change in the future? Absolutely.” 

But with power shortages looming, Mitchell believes Manitoba is already behind on solar investments. 

“As things go critical in Manitoba for a net need for energy, they’re going to have to come back and address this, because a few gas turbines isn’t going to do it,” Mitchell said. 

“I think diversifying the grid and making it healthier and stronger is the way to go, and you can do that very easily with renewables.”

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.

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.

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.

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.”

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

• 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.”

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.