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

• Canadian law requires provinces to implement a carbon pricing system for major industrial polluters as a way to reduce greenhouse gas emissions.
• But Alberta’s carbon pricing system isn’t producing the intended results, in part because its effective carbon price is too low to incentivise companies to reduce their emissions.
• It’s a sticking point in Alberta’s and Canada’s negotiations over whether and how to build a new pipeline to the West Coast. The two jurisdictions missed an April 1, 2026, deadline they set for themselves for agreeing on a new carbon pricing framework in Alberta.

Alberta and the federal government have been negotiating for months in an attempt to finalize a memorandum of understanding meant to pave the way for two key projects: a new pipeline to the West Coast and a massive carbon capture and utilization project in the oilsands.

Some elements of that deal have been hammered out, but one issue has proven tricky — an agreement on the industrial carbon price (once again, it’s not a tax).

The deal signed by Alberta Premier Danielle Smith and Prime Minister Mark Carney last year called for a new framework on industrial carbon pricing by April 1, a deadline that came and went. 

So what exactly are they talking about and what could we expect to see?Here’s a primer on what it all means, from who pays for what to why oil companies really don’t want to spend their own piles of cash.

What is the industrial carbon price?

The consumer carbon price (RIP) is what most people think about when they hear about a carbon tax or a carbon price (it’s truly not a tax, but we’ll call it that, if you insist). That since-deceased mechanism was designed to impose a cost on people to incentivize change. Think about “sin taxes” on cigarettes as one example. Make a tank of gas more expensive and maybe people will drive less.

The industrial price, snappily named the “output-based pricing system” in federal lingo, targets large industrial emitters. Like the consumer version, the price is meant to incentivize emissions reductions. The more efficient a company, the bigger the savings. 

Each province manages its own industrial carbon price scheme. They can design their own, as long as its reduction potential is considered equivalent to the federal version, or they can simply use the federal system.In Alberta, it’s known as the Technology Innovation and Emissions Reduction Regulation, but everyone just calls it TIER.

Okay, but how does the industrial carbon price work, exactly?

This stuff can get tricky, but let’s start easy.The premise is simple: large-scale industrial emitters (think steel, oil and gas and concrete) create the highest amounts of emissions. To reduce this, the government has put a price per tonne of carbon pollution on a small percentage of emissions these companies produce to incentivize them to adopt cleaner processes that emit less carbon. The money collected from these charges is pooled and distributed back to companies for investments that support this shift in emissions-reduction technologies, like carbon capture and storage.

The government sets a specific price for a tonne of emissions from a company. It also sets a threshold — if you pollute under that threshold, you don’t pay the carbon price, but if you pollute more than that threshold, each extra tonne is priced.

Companies, especially ones with a lot of emissions such as oilsands mines or concrete plants, want to reduce emissions as much as possible to avoid paying too much.

It’s also important to note the price applies to large emitters, with more than 100,000 tonnes of emissions in a year (equivalent to the annual emissions from approximately 22,000 cars).

The federal rules also call for incremental increases to the price to add an extra nudge. Over time, that makes the price of pollution more and more expensive, which is the entire point.

This is a policy designed to reduce pollution. Without it, pollution is free for the polluter, despite its costs to society and the environment. 

Carbon pricing is considered by many experts to be the most efficient and least disruptive way to reduce emissions. It’s a conclusion Carney himself came to both in 2015 and 2021.

Recent estimates from the Canadian Climate Institute peg the cost of the carbon price on oil and gas producers at 50 cents per barrel, with low, or non-existent, impacts for consumers across a range of products. 

Is carbon pricing all stick? Where’s the carrot?

Glad you asked.

While the carbon price encourages companies to strive to be more efficient to avoid the cost of pollution, they can also reap benefits from going that extra mile.

If a company reduces its emissions below the threshold set by the government, it earns credits. Those credits can then be sold to other companies to bring in real-world revenue.

Specifically, say one company reduces its emissions below the threshold and gathers credits. Another company that is still exceeding the threshold can come along and buy those credits and use them to cover its carbon pricing costs.

Money generated from the carbon price is also reinvested back into research and new technology development.

Win win, right?

Well, this is where things get messy. Especially in Alberta. Because the price is not really the price. 

Sorry, the price is not actually the price? What?

The memorandum of understanding between Alberta and Ottawa explicitly calls for an “effective price” of $130 per tonne of emissions. That’s because the price most people know, known as the headline price, isn’t necessarily what a credit will trade for between those two companies we imagined earlier.

The issue is that the Alberta government made changes to its industrial carbon pricing system one week after signing the memorandum that, when announced, flooded the market with credits and undermined their value. It also now allows companies to invest directly in technologies at their facilities instead of paying the carbon price. Those technologies may or may not actually reduce emissions.

Those changes could allow companies to essentially double dip — avoiding the carbon price by investing in technologies directly, and then collecting credits if their emissions drop.

Alberta also froze its headline price at $95 per tonne last year, rather than increasing the price as dictated by the federal equivalency rules. Not only is that a violation, it undermines the stability of the credit market and reduces confidence in the system for companies making decisions based on projected costs and benefits.

There was also a flood of credits from the rapid expansion of renewable power generation.

The end result is that carbon credits were trading as low as $17 per tonne last year. So while the headline price, which everyone understands as the price of carbon per tonne, might be $95, the effective price was, and is, well below. It’s currently trading between $20 and $40 per tonne.

As it stands, it’s very cheap for a facility to buy $20 or $40 credits compared to paying $95, but that’s less good for the efficient facilities selling the credits. And removes the whole point of the carbon price — making it expensive to pollute.

So what’s the plan for the carbon tax?

The agreement between Alberta and Ottawa signed last November called for a framework to increase the effective price to $130 per tonne by 2030 to be finalized on April 1. That didn’t happen.

Both governments say they continue to negotiate a plan, and rumours suggest something coming soon, but there are still no details. Last week, The Globe and Mail reported the speed at which the price will climb is the main sticking point.

One interesting aspect of the memorandum calls for “a financial mechanism to ensure both parties maintain their respective commitments over the long term to provide certainty to industry, and to achieve the intended emissions reductions.”

Translation: that means the agreement could include some sort of financial backstop for the credit market. That could mean the province would guarantee a credit price by offering to buy credits at, say, $130 per tonne.

That would help to stabilize the price and, hopefully, discourage the province from eroding the carbon pricing scheme (again). 

So we’re cool then?

The memorandum was framed around building both a new pipeline to the West Coast and the giant carbon capture and utilization project tied to the oilsands, known as the Pathways project.

The Pathways project would get carbon credits, which in turn would make that project more viable and could reduce the amount of public dollars used to build it.

However, the five largest oilsands producers behind the plan have dramatically walked back some of their enthusiasm for investing in emissions reductions.

On May 4, the group, which recently changed its name from the Pathways Alliance to the Oilsands Alliance, said it was still interested in carbon capture and storage.

“However, a project of this size requires supportive regulatory and fiscal frameworks, not an uncompetitive industrial carbon tax that no other major heavy oil producing jurisdiction faces, which would limit our industry’s ability to attract investment and grow,” reads the statement.

Jon McKenzie, the CEO of Cenovus, told investors in May the debate around oilsands development has been “myopically focused on the climate agenda,” according to the Canadian Press.

“The result of this myopic dialogue … is that we have created a set of national policies and regulations that make resource development and investment in Canada uncompetitive with the rest of the world,” he said, at the same time he announced an 83 per cent increase in the company’s profits. He also said increasing the carbon price would negatively impact the sector.

Cenovus reported $1.6 billion in earnings in the first three months of this year (McKenzie himself made $10.4 million in salary, stock options and bonuses in 2024). Suncor, another alliance company, reported earnings of $2.1 billion in the same time frame — 50 per cent higher than the same period last year.

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An investigation by The Narwhal published earlier this week details how the Alberta government allows millions of dollars of taxpayer money to wind up in the hands of ranchers grazing cattle on public land. 

It’s a complicated issue, involving ranchers, oil and gas companies, a broken regulatory system and — in many cases — taxpayers. 

Here’s the gist. In Alberta, ranchers can lease public land at below-market rates to graze their cattle. At the same time, oil and gas companies with wells on that public land must pay for yearly compensation for loss of the land and impacts from their operations. The catch? In Alberta, that money doesn’t go to the provincial government, which owns the public land, but to the rancher who leases it. 

There’s no cap on how much ranchers can receive in this way, and some receive compensation for hundreds of oil and gas wells. That means some ranchers are making a windfall — and not from raising cattle.

Ranchers say it’s fair compensation for the hassles of wells in a grazing area. But as the auditor general put it back in 2015, “current legislation allows an unquantified amount of personal financial benefit to some leaseholders over and above the benefits of grazing livestock on public land.” Some dubbed this “cowboy welfare,” when the report came out.

We set out to quantify it — and, crucially, to pinpoint how often taxpayers foot the bill.

You can read the full investigation here, but in the meantime here are five key takeaways about the broken regulatory system a former environment minister described as a “free-for-all.”

1. Ranchers leasing public land to graze cattle can earn six figures in compensation from oil and gas companies — every year

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. 

The Narwhal drew on estimates and data gathered from public sources to estimate both the cost of leasing land to graze cattle and the amount ranchers are paid per oil and gas well on the public land where they graze.

The Narwhal’s analysis found some ranchers are earning well over $100,000 per year from oil and gas payments. 

According to The Narwhal’s analysis, one leaseholder with 233 wells spread across a grazing area is earning $349,500 each year in oil and gas leases alone. Another rancher, with 164 oil and gas wells, is earning $250,000.

2. $5 million in taxpayer money has been paid to grazing leaseholders in one region of Alberta — on behalf of delinquent oil and gas companies

Albertans cannot refuse oil and gas wells when a company comes knocking. In return, they’re owed compensation from the oil and gas company for the hassle. And — crucially — if the oil and gas company fails to pay, the Alberta government foots the bill on its behalf.

To get a clearer picture of the issues in 2026, The Narwhal focused on Cypress County, the County of Newell and the Special Areas in southeastern Alberta, sourcing public records, including leaseholder maps and government payments to landowners when oil and gas companies fail to pay what’s owed.

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 found one leaseholder received almost $600,000 in tribunal payments over that period. One grazing association was paid almost $1 million — all taxpayer money.

The government is supposed to recoup those funds from delinquent companies, but previous reporting from The Narwhal shows only a small fraction of tribunal payments, less than one per cent, is ever recovered.

3. For decades, the government has been called on to fix the system

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.

In the report, the auditor general pointed to examples of ranchers receiving five times more oil and gas compensation than 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.

For decades, critics have called on the government to at least cap the revenue leaseholders can collect in compensation from oil and gas wells on public land. 

It has not.

4. Ranching associations have long argued against reforming the system

The issue of oil and gas compensation for grazing leaseholders has been controversial for decades, and includes a failed attempt by the Ralph Klein government to cap payments in the 1990s. 

That legislation was never proclaimed into law after intense backlash from ranchers and advocacy organizations. Among them was the Alberta Grazing Leaseholders Association.

Lindsye Murfin, with the Alberta Grazing Leaseholders Association, as well as the Western Stock Grower’s Association, told The Narwhal she takes issue with the idea that leaseholders are unduly benefiting from the current system.

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.

Compensation from oil and gas companies covers the hassle of oil and gas wells, including everything from chasing cattle after gates are left open, to weed control, loss of access to land as well as pollution and noise.

5. Alberta’s finance minister is among the recipients of taxpayer funds for compensation to his ranching on public land

Among the recipients of six-figure oil and gas compensation payments for grazing on public land is Alberta Finance Minister Nate Horner. 

His ranching business receives between $100,000 to $124,000 per year through contracts with oil and gas companies that operate on public land which he leases to graze his cattle, according to estimates by The Narwhal. 

And, as The Narwhal reported this week, when those companies fail to pay their bills, taxpayers have been paying the finance minister on the delinquent companies’ behalf.

Data from the Land and Property Rights Tribunal, which pays landowners — and ranchers who lease government land —  when companies fail to do so, shows Horner has received $87,246  in compensation from the province since 2021 for wells on his private property and on grazing leases. Of that, $47,200 was paid for sites on his grazing leases — in other words, he’s receiving public money for oil and gas wells on public land. 

The payments to Horner are all legal under current Alberta legislation and his press secretary, Marisa Warner, said Horner’s compensation is above board. 

“All of Minister Horner’s agricultural business holdings have been put in a blind trust since entering cabinet,” she told The Narwhal.

Updated on Apr. 30, 2026, at 10:32 a.m MT: This story has been updated to reflect that Lindsye Murfin is both the general manager of the Western Stock Growers’ Association as well as the manager of the Alberta Grazing Leaseholders Association.

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Summary

• Ranchers in some parts of Alberta can earn six figures from oil and gas sites on public land they lease from the government for below-market value — and when companies don’t pay, taxpayers foot the bill.
• The system is legal, but has been criticized by the auditor general, who called on the province in 2015 to stop allowing “personal financial benefit” from leasing public land.
• An investigation by The Narwhal reveals that one of those ranchers is Alberta Finance Minister Nate Horner, whose family has a long history in politics — and in lobbying against reforms to the grazing lease system.

Alberta Finance Minister Nate Horner’s ranching business likely receives between $100,000 to $124,000 per year through contracts with oil and gas companies that operate on public land which he leases to graze his cattle, according to estimates compiled by The Narwhal. 

And when those oil and gas companies fail to pay their bills, taxpayers have been paying the finance minister on the delinquent companies’ behalf, The Narwhal has learned.

Data from the Land and Property Rights Tribunal, which pays landowners — and ranchers who lease government land — when companies fail to do so, shows Horner’s ranching business has received $87,246 in compensation from the province since 2021 for wells on his private property and on grazing leases, according to The Narwhal’s analysis. Of that, $47,200 was paid for oil and gas sites on his grazing leases — in other words, he’s receiving public money for oil and gas wells on public land. 

The payments to Horner’s ranching business are all legal under current Alberta legislation, but the ability of ranchers leasing land from the government to collect all of the oil and gas compensation was criticized by the auditor general in 2015.

Nate Horner Ranches Ltd., located east of Calgary, holds vast stretches of grazing leases — public land that is rented to ranchers for what critics say are bargain prices. Horner’s family has operated in the area, and leased land from the province, for generations. 

The family is also a political dynasty, counting MPs and MLAs — including both provincial and federal cabinet ministers — in its tree. His cousin, Doug Horner, is a former provincial finance minister.

In Alberta, oil and gas companies must compensate landowners for the adverse impacts of their activity. The province’s current rules also allow leaseholders to retain all such money companies pay to operate on those publicly owned grazing leases.

It’s a controversial framework that, in 2015, the auditor general said was allowing some ranchers to derive undue “personal financial benefit” off public land.

The Narwhal set out to understand the scope of the problem, focusing on three regions east of Calgary with many ranchers grazing their cattle on public land. The Narwhal’s analysis found taxpayers have footed the bill for millions of dollars in payments on behalf of oil and gas companies to ranchers leasing public land at below-market rates. 

And one of the recipients of those payments is the finance minister’s ranching business.

His press secretary, Marisa Warner, said Horner’s compensation is above board. 

“All of Minister Horner’s agricultural business holdings have been put in a blind trust since entering cabinet,” she said by email, adding the “minister’s assets, property and business holdings have all been properly disclosed, and placed in a management arrangement, approved by the ethics commissioner.”

Each oil and gas well brings in an estimated $1,856. Horner’s business has 67

The Narwhal estimated how much Minister Horner’s ranching business receives from oil and gas companies by looking at property maps that list both grazing leaseholders and oil and gas sites and counting the number of oil and gas sites on leases he holds. Nate Horner Ranches Ltd. had 67 sites.

That number was multiplied by $1,500, a per site figure cited by the auditor general in 2015 as an average compensation amount. By this calculation, Nate Horner Ranches Ltd. could receive an estimated $100,500 per year.

Figures from Land and Property Rights compensation decisions, however, show that Horner’s ranching business might receive a higher price. Based on the 21 claims he has filed since 2021 for unpaid compensation, the average cost per site is $1,856, meaning he could be earning as much as $124,386.

It’s unclear if Horner has any other stakes in operations owned by family members near his own holdings. The minister’s office did not respond to specific questions sent by The Narwhal. 

Warner directed questions about the government’s position on the current system to the Ministry of Environment and Protected Areas, which oversees grazing leases.

The minister of environment and protected areas office did not respond to a list of emailed questions.

The finance minister’s grandfather was among the loud advocates against reforming the system that benefits ranchers

The issue of oil and gas compensation for grazing leaseholders has been controversial for decades, and includes a failed attempt by the Ralph Klein government to cap payments. 

That legislation was passed quickly in 1999, but was never proclaimed into law after intense backlash from ranchers and advocacy organizations. Among them was the Alberta Grazing Leaseholders Association, which was led by Horner’s grandfather, Jack Horner, at the time.

The association formed to push back against the Klein government “directly attacking property rights of leaseholders.”

Those opposed to changing the system point out that while grazing leaseholders pay less than market price to use public land, the lease comes with responsibilities and costs. Ranchers using public land pay for all improvements and maintenance of the land, as well as paying property taxes.

“The leaseholder has purchased the right from the province to be the occupant of that land,” Lindsye Murfin, the manager for the Alberta Grazing Leaseholders Association and the general manager of the Western Stock Grower’s Assocation, said in an interview. “And with those rights come a lot of responsibilities.”

Her organizations argue against a cap on the amount of money a leaseholder can earn from oil and gas sites on their leases. As Murfin points out, the more wells there are in a grazing area, the more problems a rancher has to manage. 

The Land and Property Rights Tribunal payments are part of a grand bargain with Albertans. No one is allowed to deny access to an oil and gas company that wants to drill, and in exchange the government will cover compensation if a delinquent company stops paying. 

Those payments have exploded in recent years, as more and more companies walk away from their financial obligations — even as some continue to operate.

The total in 2024 was $30 million, which represents a 4,500 per cent increase in the amount of money the government is paying for these missed payments since 2010. The government says it works to recoup those costs from companies, but previous reporting from The Narwhal shows only a small fraction of tribunal payments, less than one per cent, is ever recovered.

Horner’s experience is a striking example of the impact of regulatory failure in the province.

Almost all of the tribunal payments to Nate Horner Ranches Ltd. cover unpaid leases by AlphaBow Energy, a company that was allowed to snap up thousands of wells it did not have the resources to manage or clean up.

Five years after the company was created through a complex series of transactions, the Alberta Energy Regulator suspended its licences. The regulator transferred supervision of the sites to the Orphan Well Association — a largely industry-funded organization that cleans up sites without a solvent owner.

This left thousands of wells without a viable owner. It also meant millions of taxpayer dollars were directed to landowners and leaseholders to cover unpaid compensation — Horner among them.

That’s just one example. The orphan well inventory increased more than 29 per cent in 2025, but the levy imposed on companies to cover those costs only increased by seven per cent this year.

In the past month, the orphan inventory nearly doubled with the transfer of wells from another troubled company, Long Run Exploration. Those wells are estimated to have added another $476 million in liabilities to the association’s expenses.

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.

To estimate the average compensation for a site on Finance Minister Nate Horner’s land, each tribunal decision was cross-referenced with the number of years for which compensation was owed, and the number of sites tied to each claim. The number of sites was retrieved from albertawellfinder.com and based on the licence number attached to the tribunal decision.

Updated on Apr. 30, 2026, at 10:33 a.m. MT: This story has been updated to reflect that Lindsye Murfin is both the general manager of the Western Stock Growers’ Association as well as the manager of the Alberta Grazing Leaseholders Association.

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

• Ranchers in some parts of Alberta are earning six figures from oil and gas sites on public land they lease from the government for below market value. 
• An analysis by The Narwhal shows millions in tax dollars are going to the ranchers to cover debts owed by delinquent oil and gas companies. 
• Ranchers argue the money is fair compensation for impacts from oil and gas operations; the auditor general has criticized the “personal financial benefit” for ranchers as being too high.

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. 

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. 

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.

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.

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.”

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.”

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.

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.

The Alberta Energy Regulator has suspended the operations of beleaguered oil and gas company MAGA Energy for a raft of failures, including unpaid taxes, unpaid fees, improper care and closure of wells and failure to clean up spills. 

Last fall an investigation from The Narwhal revealed the scope of the company’s issues, from its failure to pay landowners for wells on their land to significant tax arrears it owes municipalities. 

The violations also highlighted failures at the Alberta Energy Regulator, which The Narwhal found approved the transfer of hundreds of wells and related infrastructure to the company in September 2024, when MAGA Energy owed more than $20,000 in taxes. This move was in violation of a ministerial order barring such transfers. 

Before the transfer, The Narwhal learned the company had already been describing itself as “in survival mode.”

The regulator told The Narwhal in November last year the company “met the requirements to proceed” with the transfer, but refused to answer questions when provided evidence that it was in violation of the rules. 

The suspension order notes the regulator was aware MAGA Energy had “outstanding debts to municipalities” and that it imposed extra oversight “which requires that applications regarding well licence transfers or new well applications … be reviewed through a non-standard process.”

The order suspending MAGA’s operations outlines a lengthy series of contraventions, including failed inspections, improper or non-existent remediation of contaminated land, failure to pay the Orphan Well Association levy, failure to pay municipal taxes, failure to pay minimum amounts for cleanup and a financial situation the regulator says has only gotten worse. 

The regulator said based on the long list of contraventions that it “believes that it is necessary to suspend MAGA’s wells, facilities and pipelines in order to protect the public or the environment.”

MAGA Energy now has 14 days to suspend its wells, pipelines and facilities, pay its outstanding orphan levy and provide a security deposit for its failure to safely seal the required portion of its wells. 

It has 30 days to submit a clean-up plan for contaminated sites and to begin that work, as well as to submit detailed plans to bring inactive wells into regulatory compliance and resolve all outstanding inspection failures. 

MAGA Energy is also required to provide detailed progress reports to the regulator every month. The company can only restart operations if it fulfills all of the regulator’s demands and then only at the discretion of the regulator.

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Summary

• Last week, the Alberta Energy Regulator announced thousands of oil and gas wells and pipeline segments, belonging to Long Run Exploration Ltd., had officially become orphans, meaning they have no solvent owner.
• Long Run Exploration had tried to salvage its financial situation through a deal to sell all its shares to a Chinese company for $22 million, which fell through.
• Court documents show the total cost to safely seal and clean up all of Long Run’s wells and other infrastructure is estimated to be $476 million.

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.

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.

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.

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Summary

• The All-season Resorts Act was passed in late 2024 and the related policies released in late 2025.
• The act gives the tourism minister, who has been mandated to grow tourism revenue to $25 billion by 2035, the authority to designate land for resort development.
• Critics say the new system removes guardrails and increases risks to the environment.

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.

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.

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.

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Summary

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Resort act a ‘regulatory failure’: lawyer

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

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

“There are no guardrails,” he said.

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

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

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

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

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

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

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

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

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

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

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

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

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

The system is a red flag to Fluker.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

“We are actively pursuing answers,” Vlemmiks said. 

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

 Concerns about water shortages in Kananaskis Country

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

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

But water-sharing agreements are voluntary. 

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

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

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

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

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

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

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

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

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Summary

• The Alberta Energy Regulator announced Thursday that more than 4,000 additional wells will be added to the inventory of the Orphan Well Association.
• The association currently has 4,200 wells on its list to be properly sealed.
• The number of orphan wells in the province has increased dramatically in the last decade. Orphan wells are those left behind by bankrupt companies.

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.

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