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.

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.

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.

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 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.

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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

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

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

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

Sooo, what’s really happening?

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

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

Let’s dig in. 

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

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

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

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

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

What does the data on new renewable energy projects show?

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

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

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

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

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

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

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

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

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

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

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

 What about investments in renewable energy projects?

It appears the private money that drives much of Alberta’s renewable development is drying up.A recent report by Business Renewables Centre-Canada says the deals the organization facilitates between companies looking to buy renewable power and renewable developers, known as power purchase agreements, have declined. 

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

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

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

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

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

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

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

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

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

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

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

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

But there are also continued headwinds.

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

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

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

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

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Summary

• The Alberta Utilities Commission has rejected a proposal for a massive rural data centre, citing missing information and a lack of public consultation
• The company behind the proposal, Synapse Data Centre, can reapply for approval once it has addressed the commission’s concerns
• One resident who opposed the proposal told The Narwhal she’s happy, but not letting her guard down

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

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

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

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

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

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

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

Environmental impact evaluations were also a concern for the regulator. 

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

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

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

“Given the number and significance of deficiencies, the commission has concluded that it cannot process the application with the current information in the application, particularly because of the deficiencies in the participant involvement program requirements,” the regulator said.Synapse, however, can reapply for approval once it has addressed the commission’s concerns. 

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

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

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

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Summary

• The Alberta government has tabled its budget for 2026-27, and it projects a $9.4-billion deficit.
• Falling oil prices are one big reason for the province’s worsening economic forecasts.
• One mitigation strategy the government is pursuing is wooing AI data centres to locate in the province.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

2. Expect more data centres and maybe some nuclear reactors

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

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

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

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

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

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

3. Revenue from the industrial carbon price is way down

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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Summary

• Synapse Data Centre Inc. has a $10-billion plan to build a sprawling data centre, along with a natural gas power plant to supply the electricity, in rural Alberta.
• Residents of Olds, Alta., have questions about air and water pollution — as well as the plan to use relatively new technology to keep the systems cool using less water. They first learned of the proposal in late January.
• Many of those questions remain unanswered, even as the company races towards its goal to get permits in place and begin construction in March.

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Just past the sign that welcomes drivers to Olds, Alta., sits a parcel of farmland. It’s on the edge of town, across the street from homes and tucked behind the old municipal building, which was sold to the local Co-op two years ago. 

It’s where a developer is proposing to build a $10-billion data centre, along with the second-largest power plant in Alberta, to satisfy the world’s seemingly voracious appetite for data. 

The natural gas facility, proposed by Synapse Data Centre Inc., will produce 1.4 gigawatts of energy each day, solely to power what could become the largest artificial intelligence (AI) data centre in the country. 

That’s equivalent to the daily demand for the entire city of Edmonton.

For some, including a town council wrestling with debt and eager to find new income, it’s a boon. For others, including residents caught off guard by a fast-moving developer, it raises concerns over air and water pollution, noise and more.  

That sort of investment in a town of just under 10,000 is significant.

The developer approached the town last November, and went public near the end of January regarding its plans. Synapse has said it wants to start construction in March — something Mayor Dan Daley calls “pretty optimistic.”

The data centre, if built, would be the biggest project amidst a potential building boom in Alberta, pushed by a provincial data centre strategy launched in 2024 that seeks to attract $100 billion worth of investment to the province. 

It’s also a significant test of the government’s “bring your own energy” part of that strategy, which prioritizes data centre projects that include on-site power generation, separate from the provincial electricity grid.

But closer to home, the project has raised more immediate concerns for residents of Olds.

Janae Johnson, who lives near the proposed facility, worries about how close the data centre will be to homes, but also the wetlands and fields of Olds College, just across the street. She worries about air pollution, water, noise and a project that seems to be moving fast with little public information. 

“We’re talking about the biggest plant, that’s using new technology that hasn’t been proven, that is not typically located right in a residential area,” she says.

Olds AI project announced in January — company wants to start construction in March

The Synapse data centre will actually be ten data centres and ten power plants, cobbled together on the same parcel of land on the edge of Olds, across from the agriculture and technology college. All together, the computer servers alone would eat up a gigawatt of electricity daily. 

The company says it will use a closed-loop water cooling system for both its data centre and the attached power plant, claiming it only needs to pull water to fill the systems once, a relatively new technology for data centres. The power will be produced by natural gas units tapping local reservoirs of gas.

AI data centres are the backbone of plans to dramatically ramp up artificial intelligence use in all aspects of life, from surfing the internet to use in hospitals, military applications and so much more. Data centres themselves are largely unassuming: inside are what look like rows of neatly arranged boxes — servers stacked on what look like bookshelves. 

Sandra Blyth, the economic development manager for the town’s investment agency, Invest Olds, says she signed a non-disclosure agreement with Synapse to protect some of the more detailed information, so she’s limited in what she can reveal about more technical aspects of the plan. 

She says the company approached the town in November and then moved quickly, with the project announced on Jan. 27. The land in question was rezoned to allow the project on Feb. 9 and the company says it wants to start construction in March.

Synapse still has to go through the regulatory process with the Alberta Utilities Commission, the provincial regulator of the electricity grid, and Alberta Environment and Parks, making the March construction start date unlikely. 

“There’s a lot of regulation to get through, and so it’s hard to say, but that’s the target,” Blyth says about the construction timeline. “Targets are good.”

But the speed of that target has caused concern.

Residents concerned about emissions, water contamination and more

Johnson, who lives near the site, says there’s been a lack of clarity on the project and a lack of transparency from council, which doesn’t help convince her of the project’s benefits. She also learned about the development in late January, when three representatives from Synapse knocked on her door. 

“My biggest concern is going to be air pollution, noise pollution,” she says. “We have populations of deer and geese and loons and beavers. What is the impact of this going to be? That has not been addressed whatsoever.”

She’s not alone. Dozens of letters and comments sent to town council in February reveal extensive concern.

“Has there been any consideration of the amount of emissions that the gas-fired power plant will create?” one resident wrote to the town council. 

“How will wastewater be disposed of as it will likely be contaminated?” the same resident asked.

Others wanted to see examples of existing closed-loop systems, remediation plans for the site, clarity on how air quality will be monitored and information on how contraventions would be enforced. 

Standing in the parking lot of the Co-op building, overlooking the site, Peter Grenier says he’s opposed to the project. He lives across the street from the proposed data centre.He thinks the project is too close to homes and is upset with what he sees as late consultation. 

Daley, the mayor of Olds, says he’s sympathetic to residents’ concerns, but there aren’t many answers he can provide. 

“A lot of their questions and concerns that they had directed towards council, we didn’t have answers on yet because these studies and assessments haven’t taken place yet,” he says.

Electricity use of proposed data centres in Alberta would be more than double the province’s average

Jason van Gaal, the president and CEO of Synapse, says the company has submitted applications to the utility regulator and the government, both of which are focused on the power generation aspect of the project. 

He says the company could, “in theory,” start construction on the data centre prior to receiving those approvals.

The natural gas power generation will produce greenhouse gas emissions as well as pollutants including nitrous oxides, something van Gaal says is a focus of provincial regulations.

“What the province wants to see is nitrous oxides below a certain threshold, and other things as well, but the reason they focus on nitrous oxide is because that is, typically, for natural gas plants, the hardest one to be compliant with.”

Van Gaal wasn’t able to provide figures on greenhouse gas emissions from the project. Natural gas produces methane, a potent greenhouse gas. He did say there could be carbon capture on the power plant in the future. 

The Synapse project isn’t the only project of its scale proposed for Alberta. The list of data centres that want to connect to the provincial grid include one project near Red Deer that would reach 1.8 gigawatts, another near Calgary requiring 1.4 gigawatts and several nearing the one-gigawatt mark. 

The province capped the total amount of power that could be drawn from the grid for all data centres at 1.2 gigawatts for the first round of applications. All of that power went to two projects, both near Edmonton, leaving 40 to wait in the queue or build their own power source.

In total, power demand for proposed data centres currently listed by the Alberta Electric System Operator sits at 21.2 gigawatts per day — more than double the average electricity use for the entire province. And that figure doesn’t yet include the Synapse project.

“Someone asked me at one of the meetings, are you okay living beside it? And I said, ‘Sure, no problem.’ The more I’ve gone down this, the less concerned I would be about it,” says van Gaal. “If the community wants me to live beside the natural gas plant myself, I don’t have a problem doing it.”

‘Feeling the pinch’: huge AI investment could help Olds’ finances

The prospect of a multibillion-dollar investment is particularly attractive, as Olds has struggled financially in recent years. Olds lost millions building a local fibre optic network that it recently sold to Telus at a loss, a large cannabis operation pulled up stakes in 2022 and provincial funding for municipalities has dried up. The town has eaten into reserves and cut services as it fights to balance the books.

Mayor Daley says Synapse would be responsible for paying to bring utilities such as water and sewage to the area, a significant investment that could attract more businesses to that currently unserviced area of town. 

“The tax revenue that’s going to come off of that will definitely help,” he says. “As all other municipalities in Alberta, we’re feeling the pinch of the cutbacks to our funding from the provincial government.”

While that funding shrinks, the province is busy promoting data centres as an economic driver. There’s also more than $1 billion from the federal government as part of a data sovereignty strategy. 

That funding, and the enormous amounts of corporate money being dumped into the building boom, mean the dilemma of data centres is something more and more communities will face. 

Grenier, who worries about looking out over the data centre instead of the sunrises he has enjoyed for years, expresses a sort of fatalism about it, especially after Alberta Premier Danielle Smith weighed in with her support, saying on Facebook she’s “thrilled” to welcome the project.

“Once your premier has it on her Facebook page — she’s done, boys,” Grenier says.

Updated on Feb. 23, 2026, at 2:28 p.m. MT: This story has been updated to correct a typo. A previous version of this article stated Synapse Data Centre Inc. could become the largest artificial intelligence data centre in the county. It could be the largest in the country, not the county.

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

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

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

Alberta is looking to borrow big money

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

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

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

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

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

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

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

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

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

An Alberta minister travelled to Montana to talk about electricity

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

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

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

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

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

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

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

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

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

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

Alberta is (again) musing about nuclear power

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

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

Albertans are still mad about coal mining

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

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

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

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

Alberta is full-steam ahead on data centre proposals

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

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

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

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

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

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

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If you’re in Western Canada — heck if you’re anywhere in Canada — you’ve probably heard about pipelines lately (or for the past seemingly million years). It’s particularly true since late last year when Prime Minister Mark Carney signed an agreement with Alberta meant to incentivize a new oil pipeline to the West Coast.

The last time Canada was so into talking about pipelines was about 10 years ago, a national back and forth that ended with the cancellation of the Northern Gateway pipeline proposal and the federal government buying and building what turned out to be a very expensive Trans Mountain expansion. 

Since then, oil has started to flow through the government-owned project, drastically increasing shipments to the coast and expanding market access to other countries (somewhat, more on that later). That has helped put more money into the very large pockets of oil companies, but hasn’t been enough to satisfy the patch or the Alberta government. 

Trans Mountain is still front and centre in the new national debate — a debate that includes whether or not the country’s oil industry actually needs a new pipeline. That’s not helped by a lack of clarity around how much oil is actually flowing through that pipe, how much could flow through that pipe, how much oil Canada actually has to move to international markets and how much of that oil other countries actually want. 

There’s also the fact that no company has indicated it wants to actually build a new pipeline. 

Here, we break down where we are, where we could go and why it all matters.

Quick recap: TMX, KXL, Northern Gateway, Energy East … what’s what?

For a quick refresher, since the 1950s the Trans Mountain pipeline has been taking oil from Alberta down to the Lower Mainland of B.C. where it is shipped to overseas markets as well as the west coast of the U.S.

In 2012, a private company, Kinder Morgan, announced it wanted to greatly expand that network by building a new pipeline (referred to as the Trans Mountain Expansion, or TMX) alongside the existing one. In 2018 it suspended non-essential spending on the project and warned it could ditch it entirely amidst mounting opposition and costs.

In 2016, as Kinder Morgan was struggling, the government under Justin Trudeau scuttled the proposal to cut the Northern Gateway pipeline project through the great rainforests of northern B.C. It purchased the troubled Trans Mountain from Kinder Morgan two years later to ensure oil flowed to the coast.

That expansion project ultimately cost taxpayers a whopping $34 billion — almost $30 billion more than initial estimates. Oil started flowing along the expanded network in May 2024.

Between the scuttling and the purchasing, TC Energy announced it would kill its Energy East pipeline proposal that would have carried oil across Canada to the East Coast in 2017. Later, former U.S. president Joe Biden cancelled TC Energy’s Keystone XL expansion, backstopped by Alberta taxpayers to the tune of $1.5 billion. Proving that no pipeline proposal is ever truly over, just undead, Keystone XL could make a comeback. 

But after all that, Trans Mountain remains “Canada’s only pipeline system transporting oil products to the West Coast.” The company says it operates a nearly 1,200-kilometre pipeline network with room for 890,000 barrels of petroleum products to be shipped each and every day. That translates to approximately 141 million litres, or nearly 60 Olympic-sized swimming pools.

Okay, so do we have enough pipeline capacity or not?

There’s a lot of talk about how much oil is flowing through Trans Mountain and whether there’s even enough extra to warrant the new pipeline endorsed by Alberta Premier Danielle Smith (which still doesn’t have a company that wants to build it). 

In short, no. 

Trans Mountain, which increased its capacity to 890,000 barrels per day from 300,000 barrels per day, is not full and hasn’t been since it opened. But that’s only part of the story.

On average, between June 2024 and June 2025, the pipeline was 82 per cent full, with a low point of 76 per cent and a maximum of 89 per cent, according to the Canada Energy Regulator.

That is far below Trans Mountain’s forecasts of 96 per cent utilization between 2025 and 2027.

The actual numbers do go up and down and vary from season to season. Trans Mountain CEO Mark Maki told Global News in November that the pipeline was at 90 per cent or higher, though he expected that to dip in the months to come due to seasonal maintenance in the oilsands.

Most of the room in the pipeline, 80 per cent, is set aside for regular customers, including Cenovus, Canadian Natural Resources and ConocoPhillips, on long-term contracts, while the remainder is set aside for clients looking for shorter spot contracts.

The regular shippers are using the pipeline, essentially filling their quotas, but there is little apparent appetite for spot shippers to book passage. Nonetheless, Maki has speculated the pipeline will be full by next year.

Why is the Trans Mountain pipeline not full yet?

The answer to this is a bit complicated, and depends on individual producers and contracts. But one factor is the cost of shipping on Trans Mountain. 

On average, Alberta produces more than four million barrels of oil per day. That’s enough to fill Trans Mountain, but there are already several other pipeline systems in use, too, and according to the Alberta Energy Regulator, all of them together could carry 5.4 million barrels per day.

But it’s not just the amount of oil that impacts pipeline usage. Pipelines are owned by companies — or governments — which charge fees for companies to move their products.

The Trans Mountain expansion ended up costing so much that the tolls it charges customers to move oil are much higher than other pipelines, according to credit rating agency DBRS Morningstar. At least one of those other pipelines, Enbridge’s mainline system into the U.S., also has excess capacity. 

Essentially, competition is limiting uptake on shorter Trans Mountain contracts. 

On the flip side, the pipeline has opened new markets — think, Asia — where producers can sell their oil for more money per barrel.

Back up, what’s actually flowing through the pipeline, and … how?

Let’s back up for a minute. What exactly flows through the pipeline? And how do different companies pay for space?

The Trans Mountain pipeline carries oil, obviously, but it also carries refined products including jet fuel and sometimes those products will be in the pipeline at the same time. 

Those products will all move in segments, a batch of heavy oil, for example, followed by a batch of refined fuel so that it doesn’t all get mixed up — although some mixing does occur where one segment meets the other.

Those with long-term contracts will pay to reserve a certain amount of space — think, volume of product to be shipped — on the pipeline, while spot shippers will pay to book short-term space based on how much they have to ship. 

All of it is pumped through the pipelines with the help of pumping stations that push the product to terminals on the West Coast.

If there’s so much extra pipeline space, why is there a push for another pipeline?

To recap, right now, there’s enough pipeline space for all the oil Alberta produces. And that space could increase without introducing a new pipeline into the mix. Enbridge plans to expand its existing mainline network into the U.S. Meanwhile, Trans Mountain is planning to increase its capacity by essentially making the oil move faster using an additive and adding more pumping stations. (Though, it notes some plans are “subject to confirmation of commercial interest including shipper agreements for additional volumes.”) But the gist is: the faster oil or other products can flow through the pipeline, the more it can ship.

Those projects alone — on existing pipelines and routes — could add another one million barrels per day in transport in coming years. The zombie of Keystone XL? Room for another 800,000 barrels.

Oil production is not expected to increase dramatically in Alberta in the coming year, with depressed prices chilling major investments and most companies focused on reducing costs and waiting for improved returns, according to a state of the industry report published by Enserva, the industry group which represents the service side of the oilpatch (think drillers). 

Enserva also estimates plateaued production in the oilsands in 2026, as well as reduced drilling in both Alberta and Saskatchewan for conventional wells.A glut of oil on the market, and planned increases in production from Organization of the Petroleum Exporting Countries (OPEC) members, isn’t expected to improve pricing, according to the report.

There’s also the lingering question of how much oil could be produced in Venezuela, following the recent attack from the U.S., which happened shortly after the report was released.

But that hasn’t stopped the Alberta government from pushing for a doubling of production — and a new West Coast pipeline that could add capacity for another one million barrels. Its latest argument is that the prospect of Venezuelan oil flooding U.S. Gulf refineries is an added reason to increase shipping capacity to Asia. 

Of course, that could all change over the coming months — and years.

Where are we selling our oil?

Prior to the Trans Mountain expansion, virtually all Canadian oil was going to the U.S. and that meant selling at a discount. In 2024, the year the expansion opened, over 90 per cent of Canada’s oil went south. 

Since the expansion opened, more oil has flowed onto tankers and shipped to Asia, mostly China, but it’s still a relative drop in the bucket, according to the Asia Pacific Foundation of Canada.

China is the biggest Asian customer, but there are questions about its long-term demand as it aggressively pursues clean energy alternatives, as well as concerns about how easily it canpivot to other suppliers as it seeks the lowest prices on the international market.

Won’t anyone think about the emissions? Is the plan to capture them?

In 2024, the Alberta oilsands emitted 92 megatonnes of heat-trapping greenhouse gases. As a whole, Canada’s oil and gas sector emitted 212 megatonnes. For comparison, the next largest emitter was transportation, at 156 megatonnes — that’s all cars, trucks, planes and trains put together.

The pipeline deal inked by Carney and Smith requires construction of a carbon capture and storage project led by the Pathways Alliance of Canada’s five biggest oilsands producers. The multi-billion-dollar plan would include a pipeline of its own, transporting carbon to deep reservoirs in Alberta. 

It’s a project the proponents say they won’t build without significant public dollars in the mix and the governments of Alberta and Canada have pledged billions in tax credits and more.

The project, even if it lived up to expectations, would eventually achieve a net reduction of just 10 to 12 megatonnes of emissions per year.

Carbon capture and utilization projects have a long history of overpromising and underdelivering on emissions reductions. Modelling from the Pembina Institute warns that while there could be a marginal drop in overall emissions with a new pipeline and the Pathways project, those projections are likely “optimistic.”

We’re going to pay for this, aren’t we?

That seems likely, yeah. 

Alberta has already budgeted $14 million to act as the proponent for the hypothetical pipeline to the coast, despite no company offering to build it. It has also pledged tax incentives and financing for Indigenous participation. 

Sonya Savage, the former energy minister under former premier Jason Kenney, said there’s almost no chance a private company would build the pipeline without financial backstops from the government.

That’s in addition to the public dollars that would pour in the Pathways capture project.

Oh, and a new pipeline would compete with the Trans Mountain system that is struggling to pay back taxpayers for the multi-billion-dollar cost of building it, one reason its tolls are so high.

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