Some ranchers leasing public land from the Alberta government are receiving windfalls from oil and gas wells drilled on that land, according to a new analysis from The Narwhal. In some cases, taxpayers are on the hook for those payments. 

Though successive governments have long known of the multi-million dollar issue, none have acted to stop it. 

An auditor general report in 2015 castigated the province for allowing ranchers to earn undue profit off of public land. “Personal financial benefits are being derived from public assets,” the auditor general wrote. The auditor general pointed to examples at the time where ranchers were receiving five times in oil and gas compensation compared to what they paid in rent.

In other jurisdictions, like Saskatchewan, compensation from oil and gas companies does not go to ranchers using public land to graze cattle. It goes to the government.

Yet, to this day in Alberta, the system remains and problems have only increased as more and more oil and gas companies walk away from wells, or stop paying the compensation they owe to use the land, leaving the bills to taxpayers and languishing well sites to ranchers. It’s the result of decades of regulatory failure. 

Compensation from oil and gas companies, similar to a surface lease on private land, is for impact and damage from those operations, including everything from chasing cattle after gates are left open, to weed control, loss of access to land as well as pollution and noise. 

There are approximately 5,700 grazing leases across Alberta, covering roughly 5.2 million acres, or about five per cent of the province’s land base. To get a clearer picture of the issues in 2026, The Narwhal focused on Cypress County, the County of Newell and what are called the Special Areas in southeastern Alberta. We sourced public records, including leaseholder maps and government payments to landowners when oil and gas companies fail to pay what’s owed.

An analysis of data from the Land and Property Rights Tribunal, a government body that directs tax dollars to landowners and leaseholders when oil and gas companies don’t pay their rent, found that since 2021, $5 million in taxpayer money has been paid to grazing leaseholders in the region to cover company debts.

The Narwhal tried to verify the total with the tribunal. Executive director Mike Hartfield said the tribunal’s database is “designed to be self-service in nature.”

“Given the nature of this request and the time and staff resources it would take, we’re unable to verify this figure,” he said by email. 

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The issue is political, and particularly acute in the deeply conservative ridings of Alberta Premier Danielle Smith and federal Opposition Leader Pierre Poilievre. Here, a significant percentage of the land is public and rented to ranchers to graze their cattle — although some plots are so thick with wells it’s difficult to imagine enough room to graze. It’s a potential boon, but also a significant headache, for ranchers.

“[Grazing leaseholders] are rich and influential in their communities, and not just a little bit on either point,” Shannon Phillips, the NDP environment minister at the time of the auditor general’s report in 2015, said in a recent interview. “Historically, it’s an area of Alberta that has flexed its muscles within conservative movements. And, once again, not just a little bit.”

The Narwhal contacted seven Alberta ranchers with grazing leases in southern Alberta, all of whom either didn’t reply, or declined interviews, but did speak with Lindsye Murfin, who represents both a leaseholder and stock grower association.

The office of Grant Hunter, the minister of environment and protected areas who is responsible for the grazing leases, did not respond to questions from The Narwhal.

“I don’t know why anybody in their right mind would touch this topic,” one leaseholder, who declined to be interviewed, said over the phone. 

Cheap land, free money — and government bailouts

Across Alberta, landowners are struggling with increasing numbers of inactive and orphan wells on their land, or active wells owned by oil and gas companies that do not pay what’s owed to operate on their land. When an oil and gas company doesn’t pay, the tribunal can order the government to pay on their behalf. Those payouts have dramatically increased in recent years.

Previous reporting from The Narwhal has shown only a small fraction of payments made by the government on behalf of delinquent companies, less than one per cent, is ever recovered from the companies. 

Ranchers who lease public land from the government can face the same troubles getting the money they’re owed from oil and gas companies. But the financial rewards can also be significant. 

The current system in place across the province allows ranchers to rent public land from the government for a fluctuating yearly price based on a complex formula that includes how much land is needed to feed a cow, as well as market prices and costs. In return, the rancher is expected to maintain the land and pay for upgrades such as fencing, as well as cover property taxes. 

Those ranchers also have to deal with oil and gas companies, including signing contracts when the companies come knocking. In Alberta, no one can deny access to an oil and gas company that wants to drill, even if the land is public land earmarked for grazing.

It’s impossible to know the exact cost of a particular grazing lease without seeing the private contract between the government and the rancher, but estimates are possible. A report by the University of Alberta’s Alberta Land Institute estimated in 2014 that the average lease in southern Alberta was $850 per year. 

Those statistics, however, can be misleading, according to Murfin, the manager of the Alberta Grazing Leaseholders Association, which advocates for ranchers grazing cattle on public land, as well as the general manager of the Western Stock Grower’s Association, which advocates for ranchers. Murfin said, in general, grazing leases can range from 14 acres to 14 sections of land (one section is 640 acres), although she’s not sure of the exact range. In the north, they tend to be smaller, while in the south, they sprawl. A grazing lease at $850 per year would represent a smaller plot, with a 14-section stretch costing an estimated $6,000 or more in 2014. 

Between 2015 and 2026, the government’s rates have gone up three and a half times, meaning that same average would be $3,024 today, or approximately $22,000 for a 14-section lease. 

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It’s also difficult to pinpoint the compensation paid by oil and gas companies to ranchers, as each is negotiated in a private contract. However, tribunal payments covering delinquent companies offer some insight, where yearly payouts of $1,500 per well per site are the norm. That’s also the price the auditor general determined was the average price per oil and gas site back in 2015.

The number of wells on leases can range from zero to hundreds, with a select few grazing areas, particularly in southern Alberta, hosting huge numbers of oil and gas wells. And that means reaping significant financial rewards. 

Critics of the system say grazing lease rates are too low, even after recent increases, and say some ranchers are making too much profit off oil and gas operations on public land. 

Phillips, the former NDP environment minister, said the oil and gas companies are “a pain in the ass” and that ranchers should be compensated for impacts, but said there should be limits.

“It shouldn’t just be a free for all,” she said. 

Phillips said it’s a classic example of socializing the risk and privatizing the reward. 

“It is socialism at its finest, but only for rich people — for a smaller and smaller sliver of people — and it is our public land base that gives those gifts.” 

Some ranchers are earning six figures from oil and gas on public land: analysis

The Narwhal looked specifically at data from Cypress County, the Country of Newell and the large and sparsely populated Special Areas region that stretches across a wide swath of the province approximately 200 kilometres east of Calgary. The Special Areas have a unique government structure, represented by an elected board which reports to the province. 

The Alberta Land Institute report noted that while almost half of all provincial grazing leases do not have oil and gas sites, most are located in the south of the province. Meanwhile, 61.2 per cent of all wells on provincial grazing lands are located in the South Saskatchewan region.

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That was particularly true in the Special Areas, where the density of wells was slightly higher than the rest of the province, with 5.24 wells per lease, according to the report.

The Narwhal examined public land maps that show who controls specific grazing leases, as well as which oil and gas sites on those plots. 

Assuming an average price of $1,500 per oil and gas well site, The Narwhal’s analysis finds some ranchers are earning well over $100,000 per year from oil and gas payments. According to The Narwhal’s analysis, one rancher with 233 wells spread across a grazing area is earning an estimated $349,500 each year in oil and gas leases alone. Another rancher, with 164 oil and gas wells, is earning an estimated $250,000.

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In some instances, it’s difficult to know who is benefitting from oil and gas compensation, with some ranchers tied to several corporations, according to corporate registry documents obtained by The Narwhal. 

The Alberta Land Institute tracked down one leaseholder in 2014 with the “largest estimated amount of annual compensation paid on a single lease” — $1,218,000. The lease contained 812 wells.

Grazing associations can earn even more, although that money is distributed to members. The auditor general found one grazing association in 2013 “paid the province $68,875 in rent for its multiple leases and collected $348,068 in payments from industry operators for activity on its leased land.” That’s five times more in oil and gas compensation payments than they paid in rent.

Beyond what oil and gas companies pay to leaseholders, there are also millions of dollars paid to ranchers by the government. The Narwhal scraped data on payouts in the areas in question between 2021 and 2026 from the Land and Property Rights Tribunal website.

There were 3,263 decisions in total when the analysis was done at the beginning of April.

Since 2021, $5 million has been paid to grazing leaseholders to cover the debt owed by oil and gas companies for sites on public land, including significant individual payments. That estimate is based on the tribunal data. 

One leaseholder received almost $600,000 in tribunal payments over that period. One grazing association was paid almost $1 million.

Big payouts, but also big disparities

Murfin takes issue with the idea that leaseholders are unduly benefiting from the current system and said the compensation is fair considering the impacts of oil and gas operations and the costs incurred by ranchers. 

A grazing lease, she said, is similar to any other lease of public land, from oil and gas to gravel pits to forestry. 

“The leaseholder has purchased the right from the province to be the occupant of that land,” she said. “And with those rights come a lot of responsibilities.”

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She also says the impacts from oil and gas operations can be significant. “I know a guy who has to have someone hired, not for ranch work, but to manage the oil and gas companies,” she said.

That ranch has extensive native grassland and without someone “managing the damage, it would be much worse.” 

“The beef industry in Alberta is a multi-billion-dollar contributor to the economics of the province, instrumental in the maintenance and survival of rural communities and the singular reason we have large tracts of contiguous native grassland in this province,” she said.

When asked about leases where the density of wells would seem to make it impossible to actually ranch, Murfin said that just makes the job of the leaseholder more challenging and that compensation should be paid. She rejects the notion of capping the amount of money a rancher should receive from oil and gas sites on public land. 

“Their management of grazing is hard,” she said. “The grazing lease system is a stewardship-based system, so the grazing leases are inspected to make sure that the forage resource is kept healthy and productive.”

Successive governments have declined to reform the system

The Alberta Grazing Leaseholder Association was founded in 1998 in response to efforts to revamp the system by Ralph Klein’s Progressive Conservative government. 

That year, a government report called for caps on payments to leaseholders. A year later, the government introduced legislation that was quickly passed, but never proclaimed into law. 

Bill 31 would have set rates per well for leaseholders that started at $300 per well, gradually dropping to $100 per well if there were ten or more sites on a grazing lease. The bill would have capped the amount of money that could be earned from surface leases on public grazing land at $5,000 annually.

The reforms received fierce pushback from ranchers and their advocacy organizations. The Alberta Grazing Leaseholders Association’s purpose was to resist the Klein government “directly attacking property rights of leaseholders.”

Phillips, the former environment minister under Premier Rachel Notley, said her government also faced pressure when the auditor general’s report came out in 2015 and said there simply wasn’t enough time, or political will, to change the system. 

“People who have never governed will hear it as an excuse, but I’m sorry it’s just not,” she said in an interview. “You only have so much bandwidth to do so many controversial things in a four-year term.”

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The NDP government was already mired in controversy with ranchers and farmers for legislating workplace insurance and safety standards for their operations. The government also faced the impacts of an oil price crash. 

“Some elements within the grazing leaseholders certainly signalled a willingness to be less than cooperative on re-examining some of the large asks that they benefited from,” Phillips said.

That sort of pressure and the complexities of reforming the system aren’t new in Alberta and the provincial debate isn’t the only example. 

Just to the east of Cypress County, the Municipal District of Taber recently brought in reforms that have split the community. 

The municipality manages its own portfolio of grazing leases and already charged ranchers higher rates than the province, as well as restricting the amount of money a rancher on public land can receive in oil and gas compensation. Those rules were tightened even further in April: among the changes, rates were raised even more and now, after the 10-year grazing leases expire, ranchers must bid for them competitively. 

The decisions have been contentious. Among other reasons, provincial grazing leases also exist within the Municipal District of Taber, meaning neighbouring leases could have drastically different costs and returns. 

Tamara Miyanaga, the reeve of the municipal district, said balancing the wishes of long-time leaseholders against those that want to bid on that land is the most challenging thing she’s done during her time at the municipality. 

“Unfortunately, I think it will still create a divide in the community,” she said in an interview. “But council has made their decision, and now we will go forward to continue serving the residents of the [Municipal District] of Taber the best we can.”

As wells age, more public dollars could flow

In the area of southern Alberta where grazing leases sprawl and wells are dense on the landscape, the oil and gas industry is changing. 

Reservoirs that once fuelled Alberta booms, filling pockets and government coffers alike, are dwindling. More and more companies are failing to live up to their end of the bargain and the costs of cleanup continue to rise. It’s a region with some of the highest concentrations of orphan wells.

That means more public dollars will flow, even as revenues from wells in the area diminish or disappear. 

Murfin said her organization is also concerned about the issue of aging wells and delinquent operators, but it’s not something that only impacts her members. “It’s going to fall on every taxpayer in Alberta to pay for that,” she said.

She’s not convinced the government will be able to fix the problem, and takes issue with its plan to deal with old oil and gas wells. 

The government’s plan, she said, is “just a scheme that has been cooked up by somebody who has been in oil and gas his whole life.”

For Murfin, the government is moving even further away from the polluter pays principle, which would see oil and gas companies pay to clean up their messes. 

Instead, she believes the government is “downloading all the costs of reclamation on landowners and municipalities and taxpayers.”

Methodology

The Narwhal’s Prairies reporter Drew Anderson and web developer Andrew Munroe created estimates for this story from data gathered from a public government database of decisions regarding compensation oil and gas companies are supposed to pay to landowners when they put infrastructure on their land. The database is called the Land and Property Rights Tribunal database and contains tens of thousands of records of rulings. Each ruling contains information on the oil and gas company that failed to pay its bill, the land or leaseholder to whom the debt was owed, the amount owed and more. It is an extensive database, with each individual ruling page containing data on company names and grazing leaseholders or landowners, the amount paid and whether or not the site is located on a grazing lease.

Information regarding well sites located on grazing leases was obtained by purchasing municipal land maps on an app named iHunter, which provides the names of grazing leaseholders, contact information and outlines oil and gas sites on those lands.

Updated on Apr. 30, 2026, at 10:19 a.m. MT: An earlier version of this story said there was no response from the Western Stock Growers’ Association. However, after publication The Narwhal was told Lindsye Murfin is both the general manager of that association as well as the manager of the Alberta Grazing Leaseholders Association.

A beleaguered oil and gas company has left a multimillion-dollar cleanup bill in Alberta, The Narwhal has learned. Experts worry at least some of that bill could ultimately be passed on to taxpayers.

Last week, the Alberta Energy Regulator announced 4,031 wells, 383 facilities and 2,121 pipeline segments previously owned by Long Run Exploration Ltd. had officially become orphans, meaning they no longer have a legal or financial owner. The announcement did not specify a price tag for decommissioning or cleaning up any of the infrastructure.

But in a sworn affidavit filed early last year, the total liability of Long Run’s various assets was estimated at $476,834,036.95.

That means the Orphan Well Association, which is funded by an annual levy on industry and spent just under $130 million decommissioning and cleaning up old oil and gas infrastructure last year, now has a huge new liability on its hands. 

In one court document, they’re described as “mammoth environmental liabilities.”

According to the affidavit, Long Run’s oil and gas infrastructure ended up as orphans after a 2024 deal with a Chinese company fell through. That deal would have seen all of Long Run’s shares purchased for $22 million.

It wasn’t the first time the company had looked to Chinese investors when it faced financial troubles. In 2016, a financially struggling Long Run was purchased by Calgary Sinoenergy Investment Corp., its sole voting shareholder.

David Chem, reached by phone at Calgary Sinoenergy Investment Corp., told The Narwhal that Calgary Sinoenergy is a holding company and most of its shareholders are in China. “Actually, nobody calls,” he said. “I was surprised somebody called.”

Chem, who declined to share his title, said the company’s investors in China were not familiar with the concept of environmental liability regulation when they invested in Alberta oil and gas, as much of China’s oil and gas industry is state owned and private companies are not responsible for cleanup.

“A lot of Chinese investors put money into Alberta before they fully understood environmental liability because there’s no environmental liabilities in China,” he said. “They are trapped by environmental liability.”

He said the Chinese shareholders have paid for their mistake, and the blame rests on the original owners of Long Run. 

“How can you blame the Chinese owner? How can you say, ‘Oh, you guys didn’t take care of the orphan wells?’ ”

“They’re the guys who lost the most,” Chem said. “They’re the guys who lost all the money.”

Bill Andrew, who was the chairman and chief executive of Long Run Exploration at the time of that sale, pushed back on Chem’s assessment. 

“They came in with their eyes wide open,” he said by phone. “They went through a two-to-three month due diligence process,” he said, adding Long Run supplied well lists and information about all the company’s working interests. 

“We didn’t sell them a pig in a poke.”

‘The result of regulatory failure’: law professor

Meanwhile, even before Long Run’s assets were added to its inventory, the Orphan Well Association already had 4,200 wells on its list for decommissioning in Alberta. 

“In one swoop, it’s a huge jump,” University of Calgary law professor Shaun Fluker said in an interview. “It increasingly looks very likely these bets, these liabilities, will only ever be addressed with public money.”

Alberta’s Orphan Well Association is a not-for-profit organization that is theoretically funded by industry in the form of an annual levy, but has received government grants in the past and gets an annual interest-free loan from taxpayers.

“All of these problems are the result of regulatory failure,” Fluker said, describing the Orphan Well Association as an “industry-funded insurance system never designed to handle anything close to the size of these sorts of assignments.” Funding for the association, set by the regulator and paid by industry in the form of an annual levy, he said, is “wholly inadequate.”

Lars De Pauw, president and CEO of the Orphan Well Association, referred questions about the current cost of Long Run’s environmental liabilities to the Alberta Energy Regulator. “We have a multi-year plan to deal with all orphan assets including those from Long Run,” De Pauw said by email. “The plan is based on the amount provided from the orphan fund levy and other sources of revenue.”

In response to questions from The Narwhal, the Alberta Energy Regulator said by email it “does not have any further information to provide regarding Long Run’s total estimated liability.”

An unnamed spokesperson said the regulator uses tools within its liability management framework to ensure a company that takes over wells can eventually clean them up, and said it may “impose terms and conditions to mitigate any ongoing risks” and ensure regulatory obligations are met.

Andrew, who has been in the oil and gas industry for 52 years, points to the increasing number of wells falling to the Orphan Well Association. “You have to wonder who the hell was on top of them from a regulatory point of view,” he said. Andrew says when he ran Long Run, he made sure the company stayed on top of sealing old wells every year, ensuring a percentage of older wells were decommissioned each year.

Chinese investors lost millions in deal to save Long Run from financial ruin

Andrew oversaw Long Run back when it was called Galleon Energy and the company had a “nasty reputation on Bay Street and with public investors,” he said. Under his watch, the company was refinanced and its name was changed to Long Run in 2012.

In 2016, Long Run narrowly avoided financial ruin. That year, under Andrew’s leadership, the company was sold to China-based Sinoenergy Investment Corp. in a $780-million deal that included a $100-million purchase price and an agreement to take on hundreds of millions of the company’s debt, according to the Calgary Herald. 

“The deal was dubbed a Christmas miracle, reflecting Long Run’s precarious finances,” according to the Globe and Mail at the time.

Andrew told the Herald the sale was the best option for the heavily indebted company. “The alternative was grim,” he said then. The Canadian Press reported at the time that Long Run had faced a net earnings loss of $305 million in the most recent third quarter. 

“The banks were all over us. It was receivership or sell,” Andrew told The Narwhal, adding the bank facilitated an introduction with the investors.

Chem, with Calgary Sinoenergy Investment Corp., said the Chinese investors “bought from a local guy, right from the local owner.” 

“Who’s laughing? The previous owner,” he said. “They take the money and walk away.”

Andrew pushed back on that assessment. “We didn’t walk away, we sold the company,” he said.

“I did it the best I could do. I did it as fair as I could be,” he said. “When we sold Long Run, we didn’t sell it with a whole bunch of unpaid bills,” he said, adding the company was up to date on what it owed to landowners and counties.

To Chem, the big loser is the investors.

“They lost all their investment,” Chem said of shareholders in China, who he said he meets with annually. “All their investment, $800 million, is all gone.” 

“Their mistake is they should learn more about the system.”

According to Insolvency Insider Canada, “Calgary Sinoenergy is a holding company with no operation or assets other than its investment in Long Run.” All of its shares are held by another company, Sinoenergy Oil, which is based in the British Virgin Islands.

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Chem said the Chinese investors he works with are less interested in investing in Alberta oil and gas after seeing how it has played out with Long Run. “A lot of people lose money in Alberta. So I think they just say ‘no more.’ They walk away,” he said.

The Narwhal could not independently verify Chem’s assertions.

Fluker points to the massive 2015 oil price drop that saw a mad scramble for companies, many of them backed with foreign investment, to pick up Alberta oil and gas assets. “There were a number of these transactions at that time,” he said, pointing the finger at the Alberta Energy Regulator which would have approved the transfer of wells. “The regulator doesn’t appear to have scrutinized those transactions sufficiently.”

“That was really the beginning of the problem now we’re watching before our eyes.”

A last-ditch attempt to sell Long Run for $22 million in 2024 falls apart

In 2024, Long Run faced significant financial troubles again. It attempted to secure its financial footing with an agreement with a Chinese-based company, Hiking Group Shandon Jinyue Int’l Trading Corporation. That would have seen Long Run’s shares purchased for $22 million, but the company “faced challenges … transferring money out of China due to regulations of the Chinese State Administration of Foreign Exchange.”

In March 2025, Long Run entered into receivership. This is when a court-appointed third party acts as a custodian for a company facing serious financial troubles.

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Attempts to reach Long Run Exploration Ltd. went unanswered. PricewaterhouseCoopers, which is its receiver, confirmed it is acting as “manager of all current and future assets, undertakings and properties of Long Run Exploration Ltd” but declined to comment further. “The receivership proceedings are ongoing and as such, [PricewaterhouseCoopers] does not publicly comment on aspects of active receivership proceedings in the media,” spokesperson Anuja Kale-Agarwal said by email.

As is noted in documents filed by PricewaterhouseCoopers, any funds left over in Long Run’s accounts must be put toward cleaning up its mess. This requirement stems from the Redwater decision in 2019, when the Supreme Court ruled the money left over from a bankrupt oil and gas company must be used to clean up the wells it left behind before other debts, including bank loans, were prioritized.

As of February, the receiver noted it held approximately $26 million in its Long Run accounts, compared to the hundreds of millions in estimated costs to clean up its mess.

In March, it put $10 million of those funds toward clean-up.

Fewer than 500 wells were decommissioned by the Orphan Well Association last year

In 2025, Alberta’s industry-funded Orphan Well Association estimated the total cost to properly seal and clean up oil and gas on sites under its watch to be about $1.12 billion.

As of the end of March, the Orphan Well Association reported its inventory included 4,200 orphan wells that need to be safely sealed and more than 8,000 sites that need to be reclaimed.

These numbers have increased substantially. In 2013, the Orphan Well Association had just 387 orphan sites in its inventory of sites that needed to be reclaimed.

Susanne Calabrese, managing lawyer at the Alberta office of Ecojustice, is concerned what the increase means for the future. “Increasingly, profits are privatized, but cleanup is left behind — burdening landowners, municipalities and taxpayers. Companies are more than willing to take Albertan resources for profit, only to avoid the cost of cleaning up their contaminated sites through bankruptcy. This isn’t an anomaly — at this point, it seems to be their business model,” she said in an emailed statement.

“Long Run Exploration Ltd. … is not the first case of an oil and gas company walking away unscathed from costly cleanup obligations, nor will it be the last,” she added.

According to the association’s most recent annual report, fewer than 500 wells were decommissioned — meaning safely sealed — in the fiscal year ending in March 2025, while more than 2,000 new wells were added to its inventory during that time.

Andrew says it’s bad actors that contribute to the problem. He doesn’t think he’s one of them. “The properly run oil and gas companies are conscientious. They have staff and the resources to identify what needs to be done,” he said. “We don’t want to finish our lives and our careers thinking we make a mess of our country.”

“If you’re not putting a portion of your cash flow towards cleaning up your wells and cleaning up your properties, you should be lined up against the wall and shot,” he said. “Who has that sense of disregard to their country, that they leave a mess like that behind?”

According to the Government of Alberta, there are an estimated 466,000 oil and gas wells in the province. More than half of those are no longer producing, some of which have been properly plugged, while others are in a state of temporary suspension.

“It’s a bit scary when you think about it,” Fluker said. “It makes you wonder what else is out there. What’s next?”

Updated Friday, April 17, 2026, at 11:29 a.m. MT: This story was updated to include comment from the Alberta Energy Regulator that was received after publication.

Methodology

The Narwhal spoke by phone with David Chem, who responded to a voicemail left for Calgary Sinoenergy Investment Corp., which is based in Calgary and is the sole voting shareholder of Long Run. He declined to share his job title. The Narwhal also spoke by phone with Bill Andrew, former chairman and chief executive of Long Run Exploration Ltd.

The Narwhal emailed Long Run Exploration Ltd. but did not receive a response. The Narwhal also phoned Long Run’s emergency line, and was told to call Long Run’s main office. A message left at that number did not receive a response by publication time. An email sent to Wendy Barber, listed in court documents from March 2025 as Long Run’s interim chief executive officer, also did not receive a reply.

The law firm Dentons, listed in court documents as legal counsel for Long Run, replied by email to say it no longer represents Long Run and that questions should be directed to the court-appointed receiver, PricewaterhouseCoopers. 

PricewaterhouseCoopers declined to respond to specific questions, citing ongoing receivership proceedings.

In Alberta, there are growing concerns about new legislation that seeks to fast-track and expand tourism in the Rocky Mountains — which critics say comes with a huge environmental cost.

In late 2025, the Alberta government released new details about how its controversial All-season Resorts Act will play out. At the same time, it announced the first all-season resort areas, all of which are in the Rocky Mountains.

These areas are chunks of land with a new status allowing developers to apply to build year-round recreation destinations through a fast-tracked process.

The Alberta government says all-season resorts are a “key component” for the Tourism Ministry to reach its goal of growing tourism revenues to $25 billion by 2035. It says the new processes increase investor confidence and offer “tailored support to the resort development industry.”  

Critics say the rules mean developers can circumvent and undermine environmental laws.
Here’s what you need to know.

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1. The All-season Resorts Act gives the tourism minister decision-making power on some large-scale recreation projects

In Alberta, the All-season Resorts Act, passed in late 2024, makes it easier to build large-scale, year-round tourism projects on Crown land by moving approvals for these projects into the Ministry of Tourism and Sport. 

Previously, developments that raised environmental concerns would be regulated through multiple laws. They would also be reviewed by an arm of the Alberta government called the Natural Resources Conservation Board. 

The board typically reviews whether projects that require environmental impact assessments under the Environmental Protection and Enhancement Act are in the public interest, like the Three Sisters development in Canmore; or some mining, quarry or dam projects. 

Under the all-season resorts umbrella, the Ministry of Tourism and Sport gets the final say on projects, which critics say lacks the same standards of environmental review.  

It’s a system University of Calgary law professor Shaun Fluker describes as a “fiefdom of the minister.”

“There are no guardrails,” he said.

2. The Tourism Ministry has a 150-day window for approving new resort proposals

The first step toward a new resort proposal being fast-tracked through the All-season Resorts Act is a land-use change. 

Land is selected by the government to be designated as a new kind of public lands zone called an “all-season resorts area.” Before that designation, the ministry is meant to do Indigenous consultation and public engagement on the land-use changes.  

After land is designated, a developer can submit something called an “expression of interest” to signal they want to apply to develop a resort within that area. 

With the go-ahead from the Tourism Ministry, a developer submits an application, including a master development plan; environmental assessment; business and capital investment plans;  proposed approaches to landscape compatibility and integrating the resort into nearby municipalities. They have to identify constraints and “any other information as required.” 

At this stage, the developer also has to carry out public engagement and consultation

with Indigenous communities on the development plan. Once the ministry decides an application is complete, a decision is made within 150 days. 

With the green light from the Tourism Ministry, construction can start.

3. Land can be removed from provincial parks to build resorts

Three all-season resort areas were designated in December 2025 under the act and, perhaps confusingly, named after the resorts there: Fortress, Nakiska and Castle All-season Resort Areas. The first two are in Kananaskis Country and the third is near Waterton Lakes National Park. 

All three areas already offer winter activities, to varying degrees. After land is designated under the act, developers are able to apply to build or expand into as an all-season resort.

Fortress is the only area with a development application underway — an expansion of the existing ski resort that could bring in nearly 10,000 additional daily visitors.

A fourth area, Silvertip Gondola, largely in Bow Valley Wildland Provincial Park overlooking the town of Canmore, is in review to become a designated all-seasons resort area. The designation would require a change in park boundaries and an amendment to the South Saskatchewan Regional Plan, the land use framework for the region.  

To make way for these resort areas, some provincial parkland has already been shifted out of protected status. That includes 131 hectares of parkland that has lost its protected status to make way for Fortress, according to an analysis from the Canadian Parks and Wilderness Society. 

A Ministry of Tourism and Sport spokesperson told CBC the government conducted public and Indigenous consultation in 2023 about year-round resorts more broadly and “found strong support for the designations.” Critics say the decision to remove land from parks happened without public consultation. 

“It’s a little bit of the fox watching the hen house,” Katie Morrison, executive director of the Canadian Parks and Wilderness Society Southern Alberta chapter, said.

4. Experts say the whole approval process is fast-tracked

The All-season Resorts Act passed in December 2024. The first three areas were designated in December 2025, at the same time the official policy was released. 

In January, Fortress was the first to apply with a project proposal, a year-round resort in Kananaskis. The development would bring roughly 10,000 daily visitors to a water-sensitive region home to sensitive wildlife and already under strain from tourism.  

Morrison, of the Canadian Parks and Wilderness Society, said the entire legislative process, from tabling the act to implementation, including 150-day statutory timelines for decisions on applications, has been rushed. And rushing, she said, doesn’t make sense here. 

“Some of the reasons we have had delays in approval on these things is because this is a really complex landscape,” she said.

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5. The environmental assessment for the first development application under the act is not ‘credible,’ according to experts

The Fortress proposal includes an environmental assessment Morrison calls “woefully inadequate” for assessing impacts. 

Fluker, the law professor, said the inadequacy of the assessment “undermines the whole approval process.” 

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

Though the proposal raises questions around water use in drought-stricken southern Alberta, the environmental assessment does not address where more water would come from, just that it may be required. 

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

For its part, Fortress says the project team is dedicated to sustainability. “We aim to be the most water-efficient resort in Alberta,” project director Danielle Vlemmiks said in response to The Narwhal’s questions over email.

An assessment should put forth enough data for experts to evaluate the potential impacts of a project and come up with solutions, Fluker said. With this assessment, he said, “I don’t know how anybody could do that.” 

The Alberta government did not respond to detailed questions from The Narwhal.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Resort act a ‘regulatory failure’: lawyer

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

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

“There are no guardrails,” he said.

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

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

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

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

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

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

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

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

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

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

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

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

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

The system is a red flag to Fluker.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

“We are actively pursuing answers,” Vlemmiks said. 

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

 Concerns about water shortages in Kananaskis Country

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

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

But water-sharing agreements are voluntary. 

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

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

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

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

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

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

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

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

On Thursday, the Alberta Energy Regulator announced more than 4,000 additional oil and gas wells are now officially orphans, meaning the industry-funded Orphan Well Association’s list of old wells to properly seal has nearly doubled.

According to the regulator, 4,031 wells, 383 facilities, 2,121 pipeline segments and 38 pipeline installations belonging to Calgary-based Long Run Exploration Ltd. have now been turned over to the Orphan Well Association.

Before Long Run’s assets were added to its inventory, 4,200 wells were already on the Orphan Well Association’s list of wells that needed to be decommissioned.

According to the association’s most recent annual report, fewer than 500 wells were decommissioned — meaning safely sealed — in the fiscal year ending in March 2025, while more than 2,000 new wells were added to its inventory during that time.

Lars De Pauw, the president of the Orphan Well Association, said by email not all the Long Run wells need to be sealed. “Our initial review indicates that about one-third of the wells are already decommissioned but we are anticipating close to 3,000 new wells in addition to our current 4,200,” he said by email.

Organizations had already been ringing alarm bells about the issue earlier this month. At the end of March, the Alberta Energy Regulator announced it was increasing the orphan well levy — a fee charged on oil and gas licences to cover the costs of cleaning up orphan wells — by seven per cent. But as watchdogs were quick to point out, the orphan count increased 29 per cent last year.

“This is not good enough, plain and simple,” Ecojustice lawyer Susanne Calabrese said in a statement at the time. “The shortfall is already being felt in the province, and taxpayers are paying the price for the gap — all while the risks and costs continue to climb.” 

A spokesperson for the Alberta Energy Regulator said by email the new levy amount was endorsed by the Government of Alberta, adding it “will support the Orphan Well Association’s operating budget for the 2026/27 fiscal year.”

As of 2025, the Orphan Well Association estimated total costs to properly seal and reclaim orphan oil and gas sites in Alberta that were on the inventory at the time was approximately $1.12 billion.

That doesn’t include the thousands more on the list now.

“This is the largest single transfer in history, and it almost doubles the [Orphan Well Association’s] inventory overnight,” Janetta McKenzie, director of the oil and gas program at the Pembina Institute, told The Narwhal by email.

“While this single insolvency means the number of orphan wells will spike by nearly 100 per cent this year, the amount of industry funding required by the provincial government to clean these wells up has risen by only seven per cent. This is clearly inadequate for the scale of the problem,” she added. “It leaves Albertans to bear the harms associated with unremediated wells near their homes and businesses.”

So what’s this all about? Here’s what you need to know.

What is an orphan well anyway?

An orphan well is one that no longer has a legal or financial owner. 

Most often, an oil and gas company that has gone bankrupt has left behind a long list of wells that were never properly decommissioned or cleaned up — and someone has to pay for that. In the meantime, the well, or pipeline or other related facility, becomes an “orphan.” 

But even without an owner, it still needs to be properly plugged and reclaimed, according to provincial rules.

How many orphan wells are there in Alberta?

As of the end of March, Alberta’s Orphan Well Association reported its inventory included 4,200 orphan wells that need to be safely sealed and more than 8,000 sites that need to be reclaimed.

These numbers have increased substantially in recent years. In 2013, the Orphan Well Association had just 387 orphan sites in its inventory of sites that needed to be reclaimed. 

But a lot of the concern about orphan wells comes not just from the current inventory, but from the potential for thousands more to be added to the list. 

According to the Government of Alberta, there are an estimated 466,000 oil and gas wells in the province. More than half of those are no longer producing, some of which have been properly plugged, while others are in a state of temporary suspension.

Either way, once a well is no longer active, it’s no longer making a company any money.

In fact, it does the opposite. Oil and gas companies have to pay costs associated with sites they’re no longer using. 

For example, they’re supposed to pay rent to the owner of the land where the well is located, as well as taxes to the local government. That said, it has been more and more common in recent years that companies don’t pay landowners or their tax bills.

All of this means an inactive well can be a costly burden to a company, especially one that’s already struggling financially.

What is the Orphan Well Association?

Alberta’s Orphan Well Association is a not-for-profit organization that is theoretically funded by industry, but actually has received government grants in the past and gets an annual interest-free loan from taxpayers.

It takes over responsibility for cleanup when no company is legally or financially responsible for a well or related pipeline or facility.

According to the association’s most recent annual report, it spent nearly $130 million on cleaning up and sealing orphan wells, pipelines and related facilities in the fiscal year that ended in 2025. 

The Orphan Well Association is overseen by a board of directors made up of industry representatives from the Canadian Association of Petroleum Producers, Cenovus, Canadian Natural Resources Limited (CNRL) and others, as well one representative of the Alberta Energy Regulator.

Who’s supposed to pay to clean up orphaned wells?

The short answer: industry.

The idea is that all companies pay into the orphan well fund, to make a pool of money available for when companies go bankrupt, or otherwise walk away from their liabilities. Last year, the orphan well levy added up to $144.45 million.

In theory, this fund should be enough money to fund orphan well cleanup in the province. But as clean-up bills have ballooned, the auditor general and other critics have warned this may not be the reality.

“Every year that we underfund this cleanup is another year contaminants remain in the ground, water and air — putting landowners’ health, property values and livelihoods at risk. Meanwhile, taxpayers are left picking up the tab,” Ecojustice said in a statement earlier this month.

Updated at Friday, April 10, at 4:12 p.m. MT: This story was updated to include information received by email after publication time from the Orphan Well Association.

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

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

Sooo, what’s really happening?

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

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

Let’s dig in. 

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

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

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

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

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

What does the data on new renewable energy projects show?

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

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

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

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

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

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

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

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

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

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

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

 What about investments in renewable energy projects?

It appears the private money that drives much of Alberta’s renewable development is drying up.

A recent report by Business Renewables Centre-Canada says the deals the organization facilitates between companies looking to buy renewable power and renewable developers, known as power purchase agreements, have declined. 

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

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

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

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

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

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

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

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

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

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

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

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

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But there are also continued headwinds.

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

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

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

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

A massive data centre proposed for the town of Olds, Alta., has been rejected by the provincial utilities regulator. 

Synapse Data Centre’s project would have been the largest of its kind in Canada, consuming as much power in a day as the entire city of Edmonton, fed by a 1.4 gigawatt natural gas power plant built to fuel the centre.  

The Alberta Utilities Commission, which regulates power plants in the province, denied the company’s application, citing missing information and a lack of public consultation. 

“The deficiencies include, but are not limited to, errors, insufficient or incomplete information and internal inconsistency among the application documents,” reads the decision, issued on March 6. “Collectively, the deficiencies create a significant lack of clarity as to whether application requirements have been met.”

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Residents of Olds expressed concern over the project, worried about a massive power plant and data centre located across the street from homes, as well as the agricultural college and its wetlands and fields. 

Those concerns were not sufficiently addressed, according to the commission. 

It notes the public consultation process started 14 days before the application was submitted for approval, and says information packages lacked details. The company’s application didn’t include key concerns raised by residents or identify how it attempted to mitigate them, for example. 

Environmental impact evaluations were also a concern for the regulator. 

“The environmental evaluation is a draft document with missing information, including incomplete citations, missing figures and document mark-ups including highlighted text,” according to the decision. 

It says environmental evaluations were based on “preliminary desktop data” and “conclusions relating to wildlife and wetlands are made from incomplete field studies conducted during the winter.”

The application further neglected to account for potential noise impacts on residents, including the use of backup diesel generators. 

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“Given the number and significance of deficiencies, the commission has concluded that it cannot process the application with the current information in the application, particularly because of the deficiencies in the participant involvement program requirements,” the regulator said.

Synapse, however, can reapply for approval once it has addressed the commission’s concerns. 

The company did not immediately respond to an interview request, so it’s not known if this spells the end of the controversial project. Synapse previously said it wanted to start construction as early as this month. 

Janae Johnson is part of a group of residents who banded together to oppose the Synapse project and another data centre proposed for the town by Data District Inc. She told The Narwhal she’s happy about the decision, but she’s not letting her guard down. 

“We are still concerned about Data District Inc, and also know full well that Synapse can reapply once they fulfilled all recommendations from the [Alberta Utilities Commission],”  she said by email. “We are watching closely.” 

With rumours of a significant budget deficit everywhere, Alberta Premier Danielle Smith took to the airwaves on Feb. 19 to prepare the province for a shock. Rather than a frank discussion about geopolitics and the price of oil, however, the premier chose to put the blame on immigration. 

With the release of the budget on Feb. 26, the real impacts on government revenue are more clear, and it’s not immigration. In fact, reduced population growth — expected to be 1.1 per cent this year, compared to a peak of 4.7 per cent in 2024 when the province grew by 204,209 new residents — is outlined as a drag on provincial growth.

The major factor impacting Alberta’s finances is a continued over-reliance on oil and gas revenues to shore up government spending, with significant reductions in royalties from the oilsands and from the production of conventional oil and natural gas. 

Let’s dive into five factors that are having an impact on Alberta, and what the budget says about the government’s priorities and plans.

1. Dependence on oil and gas revenue has led to a massive deficit

Alberta’s budget is grim. The government predicts a deficit of almost $10 billion this coming year, followed by two more years of significant losses. Specifically, it forecasts deficits of $9.4 billion, $7.6 billion and $6.9 billion over the next three years.

That’s $23.9 billion if you’re not close to a calculator. 

The provincial debt is expected to be $137 billion by the end of 2028-29.

The biggest factor in that plunge stems from declining revenue from oil and gas in the province, one of the largest contributors to provincial coffers. 

Royalties from oilsands are down $7.5 billion from a whopping $17.2 billion in 2024-25, and about $3 billion from last year’s forecast. Other royalties took less of a hit, down approximately $1.4 billion from 2024-25.

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The risk to Alberta’s bottom line from dependence on non-renewable resource revenue likely won’t go away anytime soon, and neither will the uncertainty that has beset the global industry, with a glut of supply and weak demand that could ease by next year — or not. 

Natural gas prices, however, are expected to rise, alongside increased domestic demand. 

Despite the risks, the government continues to focus on increasing production, particularly in the oilsands, and pushing for more pipeline capacity to ship that anticipated increase. 

“Rising output will drive strong gains in oil exports and contribute to roughly a third of Alberta’s real GDP growth in 2027,” according to the budget.

2. Expect more data centres and maybe some nuclear reactors

The provincial government is eager to attract data centres, seeking $100 billion in investments.

It’s one part diversification strategy, one part fossil-fuel focused. 

The budget anticipates the construction boom could lead to an increase in domestic natural gas demand that it hopes could drive up depressed prices.

It is restricting development unless proponents bring their own power supply, rather than connecting to the provincial electricity grid.

The government will impose a levy on data centres that it anticipates could bring in more than $100 million in revenues, but says it will introduce legislation “to clarify that a data centre’s levy rate will be calculated based on actual power consumption and that power not drawn from the broader grid will be eligible for a zero per cent rate.” 

In terms of increased demand for electricity, the budget confirms the government’s commitment to nuclear power development. Just over $500,000 has been set aside “to support nuclear energy engagement activities and education initiatives to advance broader public engagement and awareness.”

3. Revenue from the industrial carbon price is way down

Revenue from Alberta’s industrial carbon price, the first system of its kind in North America, is down significantly, impacted by changes introduced by the provincial government. 

Last year, the province’s forecast revenue was $280 million, while anticipating revenue of $157 million this year. That money is used to invest in emissions reduction projects and technologies. 

The budget says more companies are relying on carbon credits to avoid payments, a trend that could reverse as credits dry up.  

That follows a freeze on the industrial carbon price last year, plus weakening compliance rules. The number of facilities covered by the industrial price is down, and the new changes allow companies to invest directly in projects to avoid paying the tax — a move critics say won’t necessarily lead to emissions reductions.

4. Alberta’s financial health is tied to geopolitical risk

The budget touts the fact Alberta is less exposed to U.S. tariffs than other provinces, but that doesn’t mean it’s not impacted by geopolitical forces beyond its control.

Those forces include the aforementioned global energy market, where prices can fluctuate wildly based on security risks, including war, Chinese demand and stockpiling of reserves, Venezuelan supply, U.S. policy and the pace of transition away from fossil fuels.

“Nationally, the dual impact of the oil price shock and slowing global economic growth is projected to weaken the Canadian dollar and prompt the Bank of Canada to lower interest rates,” according to the budget. 

“In Alberta, these conditions are expected to dampen investment and production within the conventional oil sector, leading to softer employment, stagnant wage growth and reduced consumer spending.”

But it’s not just oil and gas markets that have an impact. 

The province’s push for artificial intelligence (AI) data centres in the province also exposes Alberta to a risk, as they are vulnerable to a slowdown in investments from large tech firms, or the feared bursting of the artificial intelligence bubble. 

The whims of international governments when it comes to tariffs can also have a significant impact, and not just from the U.S. A recent deal between China and Canada significantly reduced tariffs on canola, but risks to agriculture remain.

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5. Climate change is costing us, but the government doesn’t name it

Costs associated with drought conditions totalled more than $3 billion last year, a significant part of the $4.1 billion spent on disaster relief — although the budget does not mention climate change. 

The budget says spending tied to hot and dry conditions included firefighting, reforestation, public safety, social services and support for agricultural producers impacted by drought. It notes drought impacted the agricultural sector for the fourth time in four years in 2025. 

Despite ongoing costs related to drought and wildfire, the budget for the Ministry of Forestry and Parks is down 64 per cent in the latest budget.

“The decrease is primarily due to $756 million in 2025-26 disaster and emergency expense which does not continue in 2026-27,” according to the budget. 

It’s a similar story in agriculture and irrigation, where total expenses are down $741 million “primarily due to $705 million in disaster and emergency expense that does not continue in 2026-27.”

The agriculture and irrigation budget section notes agricultural “disaster and emergency assistance has averaged $978 million per year over the last ten years, reaching as high as $2.9 billion in 2021-22.”

The overall budget does include $2 billion set aside for disaster response — half of what it was in 2025.