Enoch Cree Nation is demanding an independent investigation into the Alberta Energy Regulator for the way it handled a series of decisions related to beleaguered oil and gas company MAGA Energy, which the nation says left it with millions in cleanup costs and millions more in unpaid taxes, royalties and leases. 

In a letter shared with The Narwhal, dated Oct. 26 and addressed to Alberta Energy Minister Brian Jean and Alberta Energy Regulator CEO Rob Morgan, Chief Cody Thomas says the nation has been left with tens of millions of dollars in liabilities on its traditional territory. 

“We would estimate that this could be the largest energy related impact/expense facing any landowner in Alberta history,” he wrote. 

Those liabilities include sour gas and oil wells, pump jacks, pipelines, contamination from spills and more, according to the letter.

The nation says it was forced to pay for reclamation on affected land in order to move forward with developments, including housing, and that neither the minister’s office nor the regulator has responded to its concerns. 

“All of these liabilities can be traced back to Alberta Energy Regulator decisions that approved transactions relating to MAGA Energy and which now leave Enoch in a position whereby we will almost certainly be unable to recover the costs we continue to incur,” Thomas wrote. “We expect there are numerous other Albertans that will be in the same position.”

Neither the regulator nor the minister’s office immediately responded to questions from The Narwhal.

The First Nation wants the investigation to focus on the “full history of every transaction that has left Enoch in this position.” Those date back to 2016 when, Thomas writes, the regulator approved the transfer of “up to $100 million in liabilities from Penn West to Cedar Creek, which is now MAGA Energy.”

“Our review of various public records indicates that the [regulator] initially rejected the transfer because of concerns about Cedar Creek’s financial position.”

The letter says Enoch Cree Nation is demanding the investigation not only for itself, but “all First Nations in Alberta, our neighbouring ranchers and farmers, and all the Albertans who will now bear the costs arising from these Alberta Energy Regulator decisions.”

MAGA Energy has been the focus of considerable frustration from landowners and municipalities in Alberta. The company owes millions in taxes and leases and has failed to meet its regulatory commitments, including for well cleanup and closure. 

Those frustrations have also been directed at the regulator and its oversight of companies such as MAGA, which was allowed to acquire hundreds of new licences in 2024 despite being in financial “survival mode.”In September, 18 months after that transfer was approved, the company was ordered to cease operations by the Alberta Energy Regulator.

First Nations do not control which companies operate on their territories, as companies sign deals with Indian Oil and Gas Canada, a federal agency. 

The wells, pipelines and facilities MAGA left behind have been sitting without an owner for approximately two years, according to the nation. 

For the Enoch Cree Nation, the problems started a decade ago, but the nation also points to the 2024 transfer that impacted more landowners as further indication the regulator failed in its duties. 

Thomas says the nation is now in the position where its only recourse is seeking money from an “undercapitalized company that will never be able to cover the costs of the liabilities it is now responsible for.”

“These transactions were approved after the [regulator] knew of the undercapitalization and initially blocked the transfer,” Thomas writes. “It is difficult to see how the Alberta Energy Regulator could have approved the subsequent transactions that have directly led to the current state of affairs.”

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The estimated cost to clean up conventional oil and gas sites in Alberta has increased by $1 billion and persistent long-term issues remain, according to the latest official figures. But there are some positive signs when it comes to the number of old wells sitting idle across the province.

In total, according to the latest report from the Alberta Energy Regulator, an estimated $38 billion would be needed to properly seal and reclaim the province’s oil and gas infrastructure outside of the oilsands, up from $37 billion the year before. Critics such as lawyer and researcher Drew Yewchuk say that figure is likely lower than the actual cost, and the regulator itself stresses precise figures are hard to pin down.

The cost of cleaning up the oilsands is estimated at an additional $58 billion by the regulator. Internal documents from 2018, however, showed those estimates could be as high as $130 billion. 

According to the regulator, spending on cleanup exceeded $1 billion in 2025, including spending from companies and from the industry-funded Orphan Well Association, which deals with sites with no solvent owner. 

The annual report, dense with figures, shows a bit of push and pull in terms of progress. It can be difficult to digest, so let’s break down the good, the bad and the grey in this year’s findings.

Most companies are paying, but not all

Alberta requires oil and gas companies to pay an amount set by the regulator to decommission, remediate and reclaim their energy infrastructure when it’s no longer active, known as mandatory closure spending.

The regulator says 389 active companies have met those mandatory spending targets, or have paid deposits in lieu. While that is 80 per cent of all active companies, it also means there are 96 active companies that are delinquent, 17 of which have failed to meet their obligations for three years in a row.

Oil and gas companies are also required to pay an annual amount to the Orphan Well Association. The regulator sets a total amount to fund the association, then divvies it up between companies. 

The latest report doesn’t include a breakdown of which companies have failed to pay that levy. But comparing data from a separate report shows there are 35 active companies that have failed to both meet their clean-up obligations and to pay the orphan levy.

Number of inactive wells is down, but some older ones are lingering

Despite that delinquency, there is some good news in the report. 

The percentage of wells that are inactive — not producing, but also not yet properly sealed — has decreased to 16 per cent. But that still means 77,932 wells were sitting idle on the landscape in 2025. On Nov. 9, the inactive well list maintained by the regulator showed 77,092 wells. 

And even with the decline, the number of old wells that continue to sit inactive is increasing as a share of the total. Older wells can sometimes be more difficult and costly to clean, and can come with associated pollution from years of neglect.

Almost half of all inactive wells are more than 10 years old, some of which have been sitting for more than 20 years.

Most Alberta oil and gas companies are in decent financial shape — but certainly not all 

According to the regulator, the vast majority of the $38 billion in estimated liability — 82 per cent — is held by licencees in “low financial distress.” Financial distress is calculated using multiple criteria, including debt levels and payments relative to operations, net profits over three years and the ratio of assets to liabilities.

Currently, more than $1.7 billion of liabilities are in the hands of companies with high financial distress, which does not take into account licences still held by insolvent companies, while a further $5 billion is with those in medium financial distress. 

Those figures, however, can shift through transfers of licences for oil and gas infrastructure from one company to another.

Recent reporting by The Narwhal looking at the transfer of assets to MAGA Energy has revealed apparent gaps in the regulator’s licence-transfer process, and how assets can end up in the hands of companies unable to fulfill their regulatory obligations. 

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Documents obtained by The Narwhal offer new insights into what went on behind the scenes at the Alberta Energy Regulator when it transferred 170 oil and gas wells and related facilities to beleaguered oil and gas company MAGA Energy in 2024.

The documents, obtained through an access to information request, reveal a flurry of correspondence between the regulator and the company. MAGA, which said it was facing “severe hardship,” proposed the transfer as a “solution” to its financial woes.

“We believe this will further enhance our financial position and contribute positively to our stakeholders,” the company wrote in May 2024 as part of its pitch.

The deal was ultimately approved, apparently without the regulator independently verifying some of the evidence submitted by the company to move the deal forward, according to The Narwhal’s review of the documents.

Records show MAGA Energy submitted payment plans with three municipalities to cover taxes owed by the company to the regulator in June 2024. In Alberta, oil and gas companies are not allowed to obtain new licences if they owe more than $20,000 in back taxes. 

Past reporting by The Narwhal showed the company owed in excess of $200,000 to Sturgeon County alone, and that it violated a repayment agreement with the county four months before submitting it to the regulator as proof of compliance. 

The tax arrears, however, were just one symptom of a company in freefall. In October, just weeks after approving the transfer, the regulator said it had completed an analysis of the company’s finances and concluded “MAGA was at risk of not meeting its end-of-life obligations.”

The regulator said it performed a holistic assessment prior to approving the transfer. It’s unclear what, if anything, changed in the month after it was approved. 

Eighteen months later, with mounting regulatory violations and mounting debts, the regulator ordered MAGA to cease operations.

It has left landowners with MAGA sites on their property frustrated. 

“The Alberta Energy Regulator dropped the ball,” Jennifer Stephenson, who has four wells on her property near Drayton Valley, Alta., said. “What are they going to do to fix it? Where’s their accountability?”

‘The agreement was already breached’

The regulator touts its “holistic assessment” of oil and gas companies as a critical element in analyzing licence transfers. 

And with hundreds of millions in unpaid taxes from oil and gas companies across the province, it’s also required to block transfers when that $20,000 threshold is met. 

On June 11, 2024, the documents show the regulator informed MAGA that it was in violation of those tax requirements and that it needed to submit proof of payment, or proof of a certified payment plan within a week or the transfer would be rejected.

That same day, Mark Ross, MAGA’s then-vice-president of operations, responded. 

“Proof of active and approved property tax payment plans for the three counties, Westlock, Sturgeon and Parkland are attached,” he wrote.

Sturgeon County inked its payment plan with MAGA in October 2023 in an attempt to recoup unpaid taxes. But the county confirmed to The Narwhal that MAGA violated that agreement in February 2024 after making seven payments. 

“If this agreement was submitted as proof of compliance in June 2024, the agreement was already breached as of February 2024 and was reported to [the Alberta Energy Regulator] in March 2024,” Josephine Mah, the communications manager for Sturgeon County, said in an email. 

Municipalities do not report directly to the regulator, but submit information to the Ministry of Municipal Affairs, which then provides regular updates to the regulator.

Tony Kulbisky, the chief administrative officer for Westlock County, which also had a tax agreement with MAGA, said the company was in compliance at the time of the transfer, but defaulted in February 2025.

Parkland County, the third municipality in question, said it could not confirm any details, citing Albera’s access to information laws. Parkland County also provided a letter of support for the transfer to the regulator in June 2024.

“MAGA is an active business in Parkland County where most of its assets are predominantly located, accounting for 90 per cent of their operations and productions,” Jeff Dyck, then the county’s chief administrative officer, wrote. “The resumption of its stranded production is essential for MAGA’s success.”

By email, the regulator told The Narwhal there was “no evidence provided during the application review showing any of the payment plans … were in default,” when asked about the Sturgeon agreement, which the county said it alerted the regulator about. The regulator said it does not maintain a database on unpaid municipal taxes.

“Municipalities work directly with the ministry of municipal affairs to report up-to-date information on outstanding arrears.”

When asked how often it confirms the tax agreements submitted by companies, the regulator said it “requires listed licencees to provide the required evidence upon every application for a new well or well licence transfer.”

The regulator refused to clarify how it accesses tax information, how regularly and where that information is stored. 

Jack Alarie, the press secretary for the minister of municipal affairs, did not directly answer questions emailed by The Narwhal, but did provide a statement. 

“Municipal Affairs collects property tax arrears information from municipalities and provides regular updates to the Alberta Energy Regulator,” he wrote. “Sturgeon County’s March 2024 report on MAGA Energy Operations Ltd. was included in the next update to the [regulator], following the department’s standard process.”

Alarie did not answer questions about when that update was provided to the regulator.

Emails to MAGA’s management team, including Ross and chief financial officer, Patrick Amantea, were not acknowledged. It’s unclear if all of the company’s executives are still employed at MAGA.

Pleas and hand-delivered cheques

MAGA’s implosion started in October 2023, when another company — Tidewater — shut down a gas processing plant near Acheson, Alta., that was critical to MAGA’s operations. Without it, the company resorted to flaring off gas and cutting production. A graph provided to the regulator by Ross shows MAGA’s production fell off a cliff shortly after the plant was shut down. It never recovered. 

That calamity was a central part of the company’s pitch to the regulator. If it could just take over these new sites, it said, it could make more money and find its footing.In a presentation prepared for the regulator, Ross argued the plan would ensure “MAGA’s financial sustainability” and its ability to pay taxes, lease payments to landowners and royalties to government, as well as paying its mandated fees to the regulator and the Orphan Well Association, which oversees cleanup of sites with no viable owner. 

The signs of the company’s dire situation were clear. 

During the evaluation of the transfer request, documents show MAGA was also forced to pay outstanding administrative fees and mandatory Orphan Well Association levies to the regulator or its application would be rejected. The company had set up a payment plan for those fees but failed to make its first payment on time, the documents show.The company’s then-chief financial officer, Patrick Amantea, hand delivered a cheque for those fees to the tune of $235,617 on the last possible day for payment. 

The company was also delinquent on its mandatory spending for well cleanup and had significantly more inactive wells than active wells in its inventory: 73 per cent, compared to an industry average of 38 per cent, according to the documents.

Further, the regulator later said the company was informed in January 2024, eight months before the transfer was approved, that MAGA’s compliance rate from field inspections was significantly lower than the industry average of 75 per cent. 

It’s unclear what MAGA’s rate was, but at the end of 2024, the regulator noted the compliance rate had only declined, hitting a low of 37 per cent.

Despite those signs of distress, and the pleas by the company to approve the transfer as a last-ditch attempt at survival, the approval process continued.

In late August 2024, the regulator issued a conditional approval of the transfer of 170 wells and related facilities to MAGA Energy — with the caveat that the company first pay a security deposit of almost $5.5 million. MAGA objected, arguing it should not have to pay the deposit for several reasons, including its claims that data on its reserves had been misinterpreted and that the sum would be “prejudicial given the already reduced cash flow as a result of Tidewater’s decision” to close its gas plant. 

Less than two weeks later, the regulator issued a revised approval of the transfer, with no security deposit required.

When asked why the requirement for security was rescinded, the regulator said it wasn’t required, “based on the holistic assessment of the application.”

The regulator also said correspondence from MAGA outlining its financial strain was not considered in the review process.“Financial capability alone is not a factor to determine licence transfer decisions,” reads the email, signed AER Media. “The Alberta Energy Regulator has no control over what licencees share verbally compared to the financial data that is considered in a licence transfer review.”

The regulator refused to answer what changed between the assessment conducted during the review period and the assessment conducted one month later, which determined MAGA was at risk of not meeting its end-of-life obligations.

An issue bigger than one company

Just months after the transfer, MAGA Energy stopped paying some landowners to lease property on their land for its newly licensed wells and facilities. In one instance, it pleaded for patience from a landowner, saying the company was in “survival mode over the last 14 months.” 

It was not the only company struggling to meet its obligations even as it continued to operate. 

In Alberta, the government will cover costs owed to landowners if an oil and gas company stops paying its leases. In 2025-26, the province paid out $48.4 million to cover unpaid leases, a steep rise from $29.8 million in the previous year. 

Previous reporting by The Narwhal showed the government doled out almost $150 million to cover leases from oil and gas companies in the province between 2010 and 2024. The government only recovered $1.4 million from oil and gas companies in that same time — less than one per cent.

Stephenson, whose property sits about an hour west of Edmonton, was one of the landowners left in the lurch who had to apply for compensation. 

“It took over a year through the government to get my money,” she said, adding she’s frustrated taxpayers foot the bill. 

“We’re all paying. You’re paying me,” she said.

The Rural Municipalities of Alberta, an umbrella organization representing municipalities across the province, estimated in 2025 that companies owed more than $254 million in unpaid taxes and municipalities have written off an additional $200 million, money that will never be recovered. 

The organization says $100 million of the remaining taxes are owed by 201 companies that are still operating.

Earlier this year, the organization collaborated with the province to draft a report with recommendations to address the ongoing issue of unpaid taxes, including clearer processes and more stringent requirements for transferring oil and gas licenses. 

The government has not yet implemented changes in response to that report, but Alarie said the government has accepted the recommendations, “including more detailed reporting from municipalities to support the [regulator’s] oversight.” 

MAGA Energy has until September 2027 to safely seal its oil and gas sites.

In the meantime, landowners like Stephenson are stuck. She said she’d be happy to see a responsible company take over the wells and resume operations, but wants to see the regulator and the government do a better job of preventing bad actors from taking over wells in the first place. 

She wants accountability in the long run, but simple acts could have some short-term impact. 

“Even if there was an apology or they said the ball was dropped, that would probably — even for myself — go a long way,” she said.

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On October 30, leaders from Canada and the European Union gathered in Montreal and agreed to study exporting liquefied natural gas to Europe. That same day, the head of a US$23-billion project to ship Western Canadian gas from Quebec’s North Shore was on a ferry crossing the St. Lawrence River.

“Europe needs gas. If it doesn’t come from the East Coast, it will come from the West,” Yves Crits, chief executive of Kino Aski LNG, told The Narwhal in what he said was his first media interview. West Coast liquefied natural gas, or LNG, bound for Europe will cross the congested Panama Canal, he noted, unless it can find a shorter route through Quebec.

Crits was returning from Baie-Comeau, about 400 kilometres downriver from Quebec City, where he had been meeting with local communities about the proposal and the pipeline that would be connected to it. “We’re in the information phase,” he said. “We want to develop the project with the community.”

But Kino Aski’s planning seems to be further along than that. A presentation the company prepared for the federal government months ago, obtained by The Narwhal, already mapped three possible pipeline routes: through Atikamekw territory, farther north toward Cree lands or along the path of GNL Québec’s defunct pipeline proposal. The presentation also proposed launching environmental studies and the regulatory process by mid-October, a target that has come and gone.

When The Narwhal asked about the pipeline routes in the presentation, Crits said they were rough corridors drawn without accounting for environmental constraints. A new route developed more recently does, he said — though he noted it did not yet take into account the input of Indigenous communities and will be adjusted through further talks.

The project would pipe mostly fracked gas from Western Canada through roughly 1,000 kilometres of new pipeline to Baie-Comeau, where floating facilities would liquefy up to 15 million tonnes a year. That would make it one of the largest LNG export projects in the country, larger than B.C.’s Ksi Lisims LNG (12 million tonnes a year), Cedar LNG (about three million) and Woodfibre LNG (about two million). Kino Aski is pitching itself as “low carbon,” saying it plans to build wind turbines across the province to sell energy to Hydro-Québec, which it says would offset its energy use. No regulatory process has begun for Kino Aski LNG.

Yet Ottawa is already pitching the project to investors. A federal prospectus prepared for the Canada Investment Summit, hosted by Prime Minister Mark Carney in Toronto in September, promoted Kino Aski’s “ultra-low-emission LNG” and invited investors to take an equity stake.

In response to The Narwhal’s questions, Natural Resources Canada said inclusion in summit materials “does not constitute government approval, endorsement or a determination regarding a project’s viability.”

Still, that doesn’t sit well with Lucien Wabanonik, Chief of the Anishnabe Nation of Lac Simon, whose territory lies along one of the proposed pipeline routes. “It’s a mistake to sell something without having the consent or approval of our communities or our neighbours,” he said in an interview conducted in French.

Every nation along pipeline route has been invited to be a founding shareholder: energy executive

The Baie-Comeau LNG project first surfaced as a secretive proposal from Norwegian company Marinvest Energy, which had a non-disclosure agreement with Ottawa, as The Narwhal reported in March. Crits said Marinvest then approached the Atikamekw Nation, the territorial government for three Atikamekw nations: Wemotaci, Opticiwan and the most populous, Manawan, where Crits, a Belgian energy executive, has worked with the community for about a decade. Relaunched in August and marketed as “First Nations-led,” the project is now majority-controlled by the Atikamekw Nation Council, with Marinvest as a minority partner.

Two Marinvest executives, Greg Cano and Harald Vartdal, remain on the board of the joint venture, Kino Aski LNG Inc., according to Quebec’s business registry. But Crits indicated the Norwegian company’s stake will be diluted in upcoming fundraising rounds. “The Marinvest project is dead,” he said. “We’re going with an Indigenous philosophy.” So far, the Atikamekw Nation has been an eager partner. The nation responded to a request from The Narwhal but was not able to make someone available for an interview before publication time.

“Kino Aski LNG represents a unique opportunity to demonstrate that our communities can be leading economic partners while protecting our lands, our values and our future,” Atikamekw Grand Chief Constant Awashish said in an August statement. Awashish was reelected in September with 70 per cent voter support.

But other nations along the route in Quebec say the Atikamekw Nation doesn’t speak for them. Asked whether Atikamekw’s endorsement changed his view, Wabanonik answered: “Not at all. The objective is still the protection of our land.”

In an October statement, the Innu First Nations of Essipit, Mashteuiatsh and Pessamit said, in French, that they had neither consented to the project nor given Kino Aski a mandate to “speak on their behalf,” and called for a pause. Essipit did not respond to a request for an interview by publication time. Crits said Kino Aski has met with Innu leaders several times, and that they “are not against the project” but want more information.

The Innu have been here before. In 2015, Mashteuiatsh, Essipit and Pessamit signed a collaboration agreement with GNL Québec, which proposed a similar terminal in the Saguenay region. In 2021, the nations walked away, citing their opposition to fracked gas —  fracking uses large volumes of water and is known to cause earthquakes and significant emissions — and the company’s failure to show its LNG would replace dirtier fuels. Quebec and Ottawa rejected the project in 2021 and 2022, citing emissions, impacts on Innu communities and risks to belugas. Lac Simon was opposed then, too. “At the time, the community was completely against this kind of project because of its impact on the land, the water, the air and the climate,” Chief Wabanonik said in an interview.

Crits rejects the comparison to the GNL Québec terminal, saying communities have been involved from the beginning this time and that, unlike the Saguenay site, Baie-Comeau lies east of the belugas’ main summer range. But LNG carriers are among the largest ships on the ocean, and 15 million tonnes of LNG a year would mean hundreds of tanker trips through waters used by other whales.

The CEO said Kino Aski is offering the Innu nations a stake — and that every nation along the proposed route has been invited to become a founding shareholder. That would mean benefits agreements, jobs and contracts, modelled on Western Canadian projects such as the Haisla Nation’s Cedar LNG. The company’s presentation to Ottawa calls this offer “economic reconciliation” and estimates the project would pay $8 billion in dividends to its shareholders over its first 10 to 12 years of operation.

But that model depends on the neighbouring nations saying yes. Wabanonik called the offer “the carrot at the end of the stick.” 

“It’s not the financial aspect that interests us,” he said. At a recent community assembly, families whose lands lie along the route called the project unacceptable, Chief Wabanonik said.

Kino Aski is ‘a major project for Canada’: CEO

Despite the scale of the proposal running through its territory, Lac Simon learned of the project through the news and had to approach the developer for information, Wabanonik said. That’s not what Ottawa says should come first. Indigenous Peoples need “good information” early and should help co-develop projects, Rob Van Walleghem, general counsel and vice-president of Indigenous affairs at the Major Projects office, told members of Parliament on the House of Commons environment committee on Oct. 27. When asked about Lac Simon learning about Kino Aski through the news, the CEO said Kino Aski did not communicate earlier because it did not have much to say, and noted the Atikamek election kept the nation busy.

Natural Resources Canada’s spokesperson Miriam Galipeau said Kino Aski has not entered any federal review process or been referred to the Major Projects Office, and that Indigenous consultation would be part of any federal review. Crits said the project is by nature “a major project for Canada,” for Quebec and for Indigenous communities in the East, and that the company intends to seek referral to the office “at some point.”

Once the route is set, Crits said, “it will be up to the communities to make their decisions.” Asked whether Kino Aski would proceed without approval from every nation whose territory could be affected, he didn’t answer. But nothing in federal law guarantees First Nations that final say. In 2025, the Carney government passed the Building Canada Act, which paves the way to fast-track projects deemed in “the national interest,” a concept that has yet to be defined. It requires affected Indigenous communities to be consulted — but not that they consent. Bill C-39, now before Parliament, would go further, letting Ottawa designate entire “regions of national interest” and consolidating Indigenous consultation.

The question of consent also runs through the Atikamekw nation, where some members have asked whether Wemotaci, Opitciwan and Manawan were consulted before the Grand Chief endorsed the project. Along with the territorial government, each community has its own band council and Christian Awashish, a former Chief of Opitciwan (no relation to the Grand Chief), said in August the pipeline “will not happen.” Awashish did not respond to a request for an interview by publication time. In an August Facebook post, he called for more transparency, arguing the territorial council can’t commit community lands — in Opitciwan’s case, he wrote, only the band holds constitutionally recognized Aboriginal Title.

Corporate records reviewed by The Narwhal show Kino Aski Inc. is controlled through a sovereign fund the territorial council created in March, with the three band council chiefs on its board. Kino Aski Inc.’s own board has just two members: Constant Awashish and Yves Crits.

Kino Aski hopes to capitalize on changing geopolitics and its ‘low carbon’ approach

As it pushes the Baie-Comeau project under the new structure, Kino Aski is banking on a shift in public opinion. In 2021, the Quebec government rejected another LNG project, GNL Québec, after widespread opposition. But in December 2025, 67 per cent of Quebec respondents said they supported Marinvest’s LNG project, according to an Ipsos poll commissioned by the Montreal Economic Institute. The think tank, which receives part of its funding from the oil and gas industry, concluded that social acceptability is now there.

“The geopolitical context has completely changed,” Crits said. Kino Aski’s presentation to Ottawa argues that Europe will need new suppliers: Norway’s production is expected to decline, and Russian gas is to be banned by the end of 2027. The new Canada-EU commitment to studying LNG exports pledges to consider both sides’ climate goals, which could make Europe’s long-term appetite uncertain: the European Union’s top diplomat told The Narwhal in February that Europe will “give priority to clean energy sources,” amid a global LNG glut.

Kino Aski markets its LNG as “low carbon,” and its presentation to Ottawa set a goal of carbon neutrality. Up to a third as much energy as is exported is used to prepare gas for shipping: first, compressing gas through a pipeline, then chilling it to -162 C and liquefying it, according to the document. In the United States and Qatar, that energy usually comes from burning gas, which is largely made up of methane, a potent greenhouse gas. Kino Aski would use Hydro-Québec power instead, offset by new wind farms. But its carbon-neutral claims cover only processing, not methane escaping from tankers — or the emissions from burning the gas in Europe.

For Wabanonik, those larger impacts are exactly the problem. Lac Simon’s concerns go beyond its own territory, to the cumulative effects of development on land, water, air and the climate, he said. “It’s false to believe that only First Nations will live with these impacts,” he said. “It’s society in general.”

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Canada is the world’s fourth-largest oil producer. Yet it imported about 500,000 barrels of crude a day in 2025, three-quarters of it from the U.S., according to the Canada Energy Regulator. And much of the western Canadian oil that reaches Ontario and Quebec travels through pipelines that cross the U.S. before coming back north. As diesel prices have skyrocketed, politicians across the spectrum have pointed to a solution they say is simple: build more Canadian refineries.

Case in point: in September, Conservative Leader Pierre Poilievre pushed Prime Minister Mark Carney to invest in new refineries, saying, “Canadian workers should be turning Canadian oil into Canadian fuel.” In July, Ontario Minister of Energy and Mines Stephen Lecce said Canada needs to “expand domestic refinery capacity.” Departing B.C. premier David Eby said in January that if governments have “tens of billions of dollars to spend,” they should spend it on a refinery rather than a pipeline.

Why now? “Energy security” has become a powerful political argument as the trade war with Washington has made relying on the U.S. feel riskier, and war in Iran and attacks on Russian refineries squeeze global diesel supplies. As Poilievre put it, “the current diesel price crisis will … expose our overreliance on the U.S. to refine our own oil.”

But despite current geopolitics, the idea isn’t new. “It’s like the seasons,” said Pierre-Olivier Pineau, an energy economist at HEC Montréal who has watched refinery fervour come and go for years.

The idea returns just as, in Pineau’s words, “there has never been a better time in human history to run a refinery,” profit-wise. Imperial Oil’s refining division, for example, earned $787 million in the second quarter of 2026, more than double a year earlier. The industry, meanwhile, has been busy bending the ear of the federal government. The Canadian Fuels Association, a lobby group for refineries, reported 51 communications with federal officials in the first nine months of 2026 — more than in any full calendar year since at least 2021. Most of those contacts came in the spring, when diesel prices soared.

In the face of all that, seemingly simple solutions can look like a silver bullet. The thing is, everyone The Narwhal interviewed, from the refiners’ lobby group to its critics, agreed on one thing: Canada isn’t short of refineries. 

Here’s what you need to know.

What exactly is a refinery, and what does it produce?

A refinery is an industrial plant that turns crude oil into products people can use. In Canada, more than 80 per cent of what refineries produce is gasoline, diesel and jet fuel, according to a 2024 analysis by oil market analyst Rory Johnston.

The rest includes heating oil, asphalt, propane and the base oils used to make lubricants for engines. Refineries are different from Alberta’s upgraders, which turn thick bitumen from the oilsands into lighter “synthetic” crude that refineries can then process.

How many refineries does Canada have?

Canada has 16 oil refineries, including two that make asphalt. They have room to process about two million barrels of crude a day. In 2025, Canadian refineries ran, on average, at 90 per cent of that capacity, according to the Canada Energy Regulator.

That’s enough for the country’s needs. “The Canadian market is essentially in balance,” said Carol Montreuil, vice-president for Eastern Canada at the Canadian Fuels Association. Pineau, a frequent critic of the industry, agrees. So does Ottawa. “Canada does not need more refining capacity to meet current domestic needs,” the Prime Minister’s Office said in a statement to The Narwhal. In 2025, Canada exported a net 200,000 barrels a day of refined products, it added.

The real issue is that Canadian refineries don’t process much of the oil this country is best known for: thick, heavy bitumen from Alberta’s oilsands. Heavy crude is only about a quarter of what Canadian refineries process, according to Johnston’s 2024 analysis.

For that reason, most of Canada’s heavy oil goes south, via pipelines, to refineries in the U.S. Midwest and Gulf Coast that can handle heavy crude.

How do refineries affect the people next door?

Refineries support more than 18,000 jobs in Canada, according to the industry. For their neighbours, they can be both a paycheque and a burden.

Near Edmonton, the Imperial and Suncor refineries release benzene and sulphur dioxide, among other pollutants. Limited monitoring makes it hard to pin down how much of the region’s air pollution they are responsible for, The Narwhal has reported.

Sarnia, Ont., is home to Chemical Valley, a cluster of roughly 60 industrial facilities, including three oil refineries. Residents of neighbouring Aamjiwnaang First Nation are exposed to about 30 times more benzene than people in Toronto and Ottawa. Sarnia would be the destination if Ontario and Alberta are able to make Northern Shield happen: that proposed pipeline would carry Alberta crude north of the Great Lakes.

And when the industry leaves, the impact isn’t over. Montréal-Est was a hub of refining activity by companies such as Imperial Oil, which opened the island of Montreal’s first refinery in 1916, and Shell, which closed its last in 2010. Decades after most refineries closed in the 1980s, the area has about 270 hectares of industrial brownfields, roughly the size of 330 football fields, awaiting cleanup and redevelopment.

What are the arguments in favour of a new Canadian refinery?

Gasoline and diesel prices are high, but experts say a new Canadian refinery wouldn’t necessarily ease prices at the pump. Even Montreuil concedes that local refineries offer consumers limited protection from price spikes, since fuel prices are set on global markets.

For Montreuil, it’s more about fuel supply security, which the industry has also raised in recent months, according to the federal lobbyist registry.

Canada’s refineries ensure the country has enough fuel, and without them, we’d be rationing fuel right now, according to Montreuil, who pointed to recent examples around the world. Indonesia and Russia both rationed fuel this year. While some argue refining more oil at home would mean independence from an increasingly unpredictable neighbour, Montreuil and Johnston say that isn’t our only exposure.

Another vulnerability is pipelines that carry Canadian oil back and forth across the border, such as Enbridge’s Line 5. Political skirmishes with Michigan over that pipeline are one reason Ontario Premier Doug Ford is pushing the Northern Shield Energy Corridor. Much of Atlantic Canada relies on crude, much of it American, delivered by tanker to the country’s largest refinery, Irving’s in Saint John. No pipeline exists to bring Alberta oil to the Atlantic provinces, meaning a U.S. export restriction would leave them scrambling for other fuel sources.

Heather Exner-Pirot, a senior fellow at the Macdonald-Laurier Institute, said federal clean fuel rules are another weakness, because in order to meet emissions reduction targets, suppliers blend in biofuels largely imported from the U.S. “We are artificially making ourselves dependent on an American product,” she said. She argues the rules should be redesigned, and they’ve been a constant topic in the industry’s communications with federal officials, according to the lobbyists registry.

Carney’s government announced tweaks to the clean fuel rules last week, saying it would “make it easier and cheaper for companies to comply.” Transportation is one of Canadian households’ biggest costs, according to Statistics Canada, but Pineau thinks that addressing that by scrapping clean fuel rules would “chain Canadians even more tightly to an extremely expensive way of life,” one built around the car.

On its own, experts say, a new refinery fixes none of that.

How much would it cost to build a new refinery, and who would pay?

Companies are not lining up to build a refinery in Canada, and Ottawa isn’t offering to pay for one. In a statement, the Prime Minister’s Office said the government supports “additional refining capacity where supported by market conditions.”

A large new refinery would cost $10 to $15 billion, take at least five years to build and need 20 to 25 years to pay off, according to Montreuil and Exner-Pirot. Alberta’s last attempt, the Sturgeon refinery near Edmonton, saw its original projected cost double to about $10 billion, with much of the risk carried by taxpayers, though high diesel prices have since improved its profitability.

A new refinery would also struggle to compete on a global market. India’s newest are so big that two of them could supply all of Canada, from gasoline to jet fuel and more, Montreuil said.

With the domestic market already balanced, the purpose of a new plant would mostly be exports. But there is no real export route for refined products to Europe, Ian Sanderson, a senior oil and gas analyst at the Pembina Institute, said in an interview, adding the biggest markets are in Asia and “have substantial refinery capacity to refine Canadian [crude] at a lower price.”

There’s also the issue of decreased global demand for fossil fuels. Global demand for refined oil products could peak as early as 2027, according to the International Energy Agency. “It really is an act of faith,” Montreuil said, to bet that export markets will still want Canadian fuel by 2030 or 2035.

Sanderson points to the coal phase-out in Alberta, which hit mining towns very hard. The lesson, he said, is to “get ahead of the transition” and support oil workers into new jobs.

So far, though, Canadians aren’t using less fuel.

What part of Canada faces the highest risk when it comes to U.S. energy threats?

The most immediate risk is to Ontario, whose refineries run mostly on western crude carried by Line 5 through Wisconsin and Michigan.

Michigan’s governor has tried for years to shut it down over environmental concerns. In late August, the line was offline for more than two weeks after being struck by a truck at a work site in Wisconsin. The episode offered a glimpse of the crisis Canada would face if the Americans shut Line 5 down for good, Montreuil said.

Northern Shield would carry Alberta crude to Sarnia north of the Great Lakes, bypassing Line 5. It wouldn’t add any refining capacity, though: “Same refinery, same oil, just a different route to get it there,” Exner-Pirot said. The open question is how much this new pipeline would cost, and who would pay.

Quebec has more options, but not more independence. The Valero refinery in Lévis gets its oil by tanker through the St. Lawrence River, though much of what Quebec imports comes from the U.S. And Suncor’s Montreal-East refinery gets much of its western crude through Line 9, which runs from Sarnia, so it too depends on oil that crosses the U.S. to reach Sarnia.

What would make Canada’s fuel supply more secure?

Without building a new refinery, there are other ways to shore up supply.

Canada is the only G7 country without a strategic petroleum reserve. Despite being a member of the International Energy Agency, we’re formally exempt from its mandate to hold emergency oil stocks equivalent to at least 90 days of the previous year’s net imports because we produce more oil than we import.

Consequently, when the G7 agreed in early October to release 100 million barrels of oil from emergency stocks to lower prices at the pump, Ottawa’s contribution was to stagger maintenance at its refineries so as not to affect supply. Poilievre has proposed a reserve of refined fuels, though someone would have to pay to fill and maintain it.

Another option is to expand what already exists. Adding 10 to 20 per cent to an existing refinery may be more realistic than building a new one, Montreuil said.

But “the solution isn’t necessarily to cut taxes or to produce more,” Pineau said, noting that new oil and gas infrastructure would run counter to Canada’s climate targets. Unlike past oil shocks, “there are a lot of options to move away from oil,” Sanderson added.

Whichever path Canada takes, the big decisions will largely belong to companies, as HF Sinclair showed this summer by announcing it will stop making base oils in Mississauga, Ont., at Canada’s only such plant. Base oils, used to make motor oil, were already at the centre of a global shortage.

While politicians may bring up building new refineries as an easy solution to a very complicated problem, right now at least, even the industry itself isn’t pushing for it.

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It is easy to get lost in the numbers when talking about fracking in Alberta: to be temporarily dazzled by the growth of production, the insatiable thirst for water and the profits that follow. 

The practice has seen a dramatic increase over the past 13 years, with production rising sevenfold between 2013 and 2024 to the equivalent of more than 640 million barrels of oil per year. Water consumption also soared 335 per cent, from 6.5 billion litres to almost 30 billion litres of freshwater per year.

Those sorts of figures are almost impossible to comprehend. You could count how many swimming pools that water might fill (164 million), or try to imagine a stack of barrels teetering high into the atmosphere, but what does that really mean?

In parts of rural Alberta, you don’t need those kinds of mental gymnastics to understand the scale of the industry and its impact. The evidence is all around you. Creeks run dry. Hoses and pumps seem to line every ditch. Then there are the trucks and drilling and noise.

This is particularly true in the rural areas of west-central Alberta, a long stretch of the province sandwiched between the foothills to the west and the frenetic Calgary-Edmonton corridor to the east.

It’s here where ranches, farms and communities sit side by side with a fracking boom that is outcompeting the locals for water.

What we saw this summer

Looking back on the past ten years, the summer of 2026 was an anomaly for the area of Alberta an hour drive southwest of Edmonton. Parched fields were inundated with rain early in the season, and rivers and creeks flowed with renewed vigour. Some areas received more rainfall than ever before.

But that moisture wasn’t enough to quell concerns from some residents in the Blindman and Medicine River watersheds, where fracking activity has been increasing — and water concerns are front and centre. 

Fracking involves injecting water deep into the ground to break up rock where gas is trapped in tight crevasses, often thousands of metres under the surface. That water, vast quantities of it, is almost entirely lost to the water cycle as it remains trapped in the reservoirs that previously held gas. The water that does come to the surface is contaminated.

The Narwhal spent a day travelling through the Rimbey, Alta., area with Daniel Iseli-Otto and Assar Grinde, two members of the Blindman River Watershed Society, in July this year, visiting impacted landowners, following pumping hoses to enormous reservoirs and stopping for a photoshoot among Grinde’s cattle.

There’s an image in many a head of what kind of people raise concerns over oil and gas. Former Alberta Premier Jason Kenney often dismissed those with environmental concerns as “foreign-funded radicals,” but those stereotypes don’t hold.

Butch and Nicole Smith, who live in the area, blame the construction of a massive reservoir across from their isolated property for the decline of their bison herd. They’re moving. 

Grinde, whose family has owned its ranch for generations, talks about watching the creek on that land dry up and how the oil and gas companies were still pumping water for fracking while he was left with mud. 

Iseli-Otto curses as we turn onto another gravel road, heavily pitted from the trucks moving back and forth from a fracking reservoir site. “This is industrial pulverization of county roads,” he says, as he slows down in his Ram 3500 pickup truck.

Dana Kreil, the chair of the nearby Medicine River Watershed Society, and a councillor for Lacombe County, jumped in Iseli-Otto’s truck in the afternoon. She says the road in front of her home was “trashed” by one company active in the area.

“I want them to get a bill,” she says.

Not just fracking, not just the Blindman

Travelling through rural Alberta, it feels like the frustrations that come alongside the pay cheques and the royalties of the broader oil and gas industry are increasing in step with a years-long trend of companies failing to pay their share — whether they frack wells or not. 

Even with record profits, investments and jobs don’t stack up the way they used to. Too often, oil and gas companies fail to pay their bills, and that has consequences. Unpaid municipal taxes hurt local governments — and eat into budgets for things like road maintenance — and unpaid leases force landowners to seek government compensation on behalf of delinquent companies. At the same time, there are more and more orphan and inactive wells. 

All of those local impacts intertwine with the changing climate and the associated droughts, fires and floods.

Grinde says no one really thinks of the water the companies pull from the rivers and underground aquifers until there’s not enough to go around, and then it becomes a priority. And although the summer of 2026 was altogether too wet for many farmers, the drought years are predicted to return as part of a longer-term pattern of increased volatility. 

The cause of those swings in climate are once again related to big numbers that are hard to grasp. 

$168 billion in revenue. $22 billion in royalties the government relies on. 310 billion litres of water consumed by Alberta’s oil and gas industry. Then there’s the five billion tonnes of greenhouse gas emissions from global oil and gas production, seven billion tonnes from transportation and the unfathomable heating of oceans. 

The big picture is abstract; hard to fathom. But here at Blindman Creek, the impacts are tangible. 

“It’s really obvious that it’s an issue, but it’s really hard to make it concrete for people,” Iseli-Otto says. “This is an issue for people in Calgary, this is an issue for people in Edmonton, but they don’t know. The amount of water that’s getting sucked out is mind blowing.”

Updated on Oct. 15, 2026, at 2:05 p.m. MT: This story has been updated to clarify that the five billion tonnes from global oil and gas production and seven billion tonnes from transportation refers to tonnes of emissions.

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A document meant for a behind-closed-doors group of fossil fuel advocates earlier this year got right to the point: Canada’s policies to fight the climate crisis, protect nature and defend Indigenous Rights are a “problem,” and environmental organizations are “opponents.” 

The document, a copy of which was reviewed by The Narwhal, relates to a presentation that was scheduled to occur in January 2026. It was prepared by two advocacy groups called Energy United and Resource Works, both with connections to the country’s largest oil and gas lobby group, the Canadian Association of Petroleum Producers. 

It was part of a session in which fossil fuel advocacy groups were to discuss shaping public perceptions in favour of the oil and gas industry and against the transition to clean energy, according to materials downloaded from a coordinating group’s website by The Narwhal and originally uncovered by Greenpeace Canada.

Under the heading “Knowing our opponents,” the document details work by environmental advocacy organizations and First Nations, and the funding that supports them.

It lays out how environmental non-profit groups are collaborative, well-funded — and effective. “The damage is real & intentional,” the document says of environmental advocacy in Canada, adding, “Every major ‘problem policy’ we fight traces back to an ENGO-authored framework or idea.” 

An ENGO is an environment-focused non-governmental organization. The document includes examples of “problem policies,” including the federal emissions cap, Canada’s commitment to protect 30 per cent of its lands and water by 2030 and the United Nations Declaration on the Rights of Indigenous Peoples.

The document also highlights funding for Coastal First Nations, and their stance against lifting the oil tanker ban in northern B.C. — a years-long thorn in the side of the fossil fuel industry and another “problem policy,” according to the document.

“So, what can we do about it?” the document asks of environmental advocacy in general. It proposes moving “from defence to offence” by launching “counter-campaigns,” “calling out hypocrisy” and filing “regulatory complaints” against environmental groups like the David Suzuki Foundation.

“They want to be on the attack,” Keith Stewart, senior energy strategist for Greenpeace Canada, said of oil and gas groups in an interview.

Stewart is one of the authors of the Greenpeace report “Manufacturing Petro-Populism,” which was published Oct. 8 and delves into the web of pro-fossil fuel organizations. 

The document was one of eight presentations scheduled to occur at the January “funders session,” according to an agenda published on the website of a coordinating network, Energy In Action. The session was organized for a group called Canadian Energy Prosperity. The Energy In Action website stated that it hosted a “showcase of a selection of our 30+ groups” Canadian Energy Prosperity works with.

The document was posted publicly on the Energy In Action website, where The Narwhal viewed it. The Narwhal emailed questions to Energy In Action on Oct. 5. The following day, the website became password protected.

Energy In Action and the Canadian Association of Petroleum Producers did not respond to requests for comment. Nor did the advocacy organizations Energy United and Resource Works. Canadian Energy Prosperity does not appear to have its own web presence or any publicly available contact information.

Media, including The Narwhal, singled out in internal oil and gas document

The document also singled out a government funding program called the Local Journalism Initiative. 

It included a screenshot of a story published by The Narwhal, written by journalist Matt Simmons, whose work has been supported by the initiative. The story recounts Simmons’ experience being followed by private security as he reported on a pipeline being built through Wet’suwet’en lands.

The Local Journalism Initiative is a federal program that funds news reporting in rural, remote and otherwise underserved communities. The Narwhal receives this funding for reporting in northwestern B.C. and northern Ontario.

To protect the independence of the press, the government does not directly fund media outlets. The program is delivered by independent non-profits representing different segments of Canada’s media industry. 

“It’s clear that they see some journalists as opponents,” Stewart said of the pro-fossil fuel groups behind the document. “They don’t want anyone looking too closely at what they’re actually doing.”

Material ‘appears to build on a long-standing public outreach program’: Greenpeace

Greenpeace Canada claims the Energy In Action network “appears to build on a long-standing public outreach program” by the Canadian Association of Petroleum Producers, “which seems to have been repurposed to enable oil companies to spread their message via third parties.”

Energy United founder Tim McMillan was president of the Canadian Association of Petroleum Producers for seven years, and is currently registered as a federal lobbyist on energy issues. Stewart Muir, the president of Resource Works, formerly lobbied for a pro-fossil fuel group organized by Resource Works called The Task Force For Real Jobs, Real Recovery. The task force’s website claims the Canadian Association of Petroleum Producers is a “supporter.” 

Requests for comment to McMillan and Muir’s LinkedIn pages were not returned.

Greenpeace Canada’s report says the Energy In Action network operates “under the guise of independent and grassroots entities” but actually coordinates industry-linked activities designed to “shift public discourse and actively lobby against renewable energy initiatives.”

It said the network’s “hidden funders” are investing in campaigns targeting a large cross-section of Canadian demographics and regions, using different tools like lobbying, public advocacy and digital and traditional advertising.

The network’s activities and internal materials, it said, deploy “climate disinformation, covert influence campaigns and attacks against activists.”

The Energy In Action documents should be seen as part of a broader context of an industry that’s been proactive for years in trying to shape public opinion about its activities, its climate impacts and its economic benefits, according to Shane Gunster, a professor in the school of communication at Simon Fraser University who studies oil and gas populism.

In an interview, Gunster said his research has shown pro-oil-and-gas messaging shifted over the last decade from more expensive public relations campaigns to using social media to mobilize supporters. 

He said in recent years he’s seen greater use of what he calls “pop-up groups,” which appear to be self-contained entities that focus on a particular issue in a particular geographic location, and only appear for a limited time.

“Groups that are not explicitly connected to particular funders or industry itself can do things that industry itself would find challenging to do or to say,” he said.

He said the group of funders tied to the activities Greenpeace uncovered are supporting particularly aggressive messaging, but that isn’t always the case with pro-oil-and-gas campaigns.

Canada passed legislation in 2024 to crack down on greenwashing, which is when companies make misleading claims about how environmentally friendly their products or actions are. It created a requirement for companies in Canada to back up their green claims with evidence. After it passed, oil companies scrubbed their websites and social media feeds. 

Although Prime Minister Mark Carney’s government rolled back a clause stipulating that this evidence be based on internationally recognized standards, several oil companies were still citing the law as a reason why they can’t disclose more information. 

Gunster said he felt the anti-greenwashing changes were a factor, but not necessarily the driving force behind the pro-oil-and-gas messaging shift towards pop-up groups, which he began seeing before the anti-greenwashing law was in place.

There is public evidence that at least some of the entities Greenpeace connected to the Energy In Action network have received funding from oil companies themselves. 

According to corporate disclosure records, Cenovus, one of Canada’s largest oil and gas companies, has funded seven of them, including Resource Works. Cenovus is a member of the Canadian Association of Petroleum Producers, and Cenovus president Jon McKenzie is also the chair of the association’s board.

Cenovus proactively discloses its advocacy funding, while some other prominent oil companies do not. 

There’s no indication that the funding Cenovus has provided is directly related to the public advocacy activities reported by groups such as Resource Works during the Canadian Energy Prosperity sessions. Cenovus did not return a request for comment.

Groups tied to Energy In Action are funding disinformation: Greenpeace

Another document, a video presentation viewed online by The Narwhal, introduced itself as a “performance update for CEP,” the acronym for Canadian Energy Prosperity. The beginning of the video is dated July 2, 2025, and states that it would take place at the Calgary Petroleum Club.

That video highlighted four pro-fossil fuel ad campaigns by the organization Debunk Inc., which claims its mission is to “challenge misinformation.” Debunk’s video said the campaigns were “thanks to CEP’s support,” but did not specify who funded them or how much funding they received.

One of Debunk’s ads defended the use of natural gas in homes. Another attacked a proposal to limit heat-trapping carbon pollution from the oil and gas industry. A third downplayed the necessity of transitioning to lower-emissions fuels, and a fourth suggested liquefied natural gas, or LNG, could lead to “lower” emissions.

A Harvard study has shown that low levels of pollutants seep into homes with gas heat, while gas stoves have been associated with increased risk of asthma in children. Scientists say a disputed theory long favoured by the industry, that LNG can displace coal power abroad, underestimates the climate impact of equipment leaking methane, the main component of natural gas.

Each of these campaigns achieved results, the video claimed. The most successful was the anti-emissions cap campaign. Debunk claimed it had reached “up to 1.5 million Canadians” each month, and scored 22.3 million total views in 2025. 

The Calgary Petroleum Club did not return a request for comment.

On the Energy In Action website viewed by The Narwhal, an individual webpage also featured content from Debunk, listing the four campaigns as well as a “top performing post” which claimed it is “debunking the ‘complete fabrication’ of climate change.” 

That post, which the webpage said received “over 3,000,000 views,” contained a video claiming carbon dioxide does not cause harmful climate change. Hundreds of global climate scientists working under the United Nations Intergovernmental Panel on Climate Change have confirmed that the burning of fossil fuels is “unequivocally” responsible for recent global warming.

The Debunk webpage on the Energy In Action website featured a social media post claiming, “We’re wasting a lot of money for very little, if any, gain with all this climate hysteria.”

That post contains another video claiming the amount of human-caused carbon dioxide emissions in the atmosphere isn’t a significant problem. Concentrations of carbon dioxide in the atmosphere have increased dramatically in less than two centuries, recently to levels that have not been seen in millions of years.

Debunk did not respond to requests for comment. Founders Anastasia Columbos and Britni Weston are described on the website as “two Canadians with deep roots in the energy industry.” Neither responded to requests for comment on LinkedIn.

Greenpeace is calling on “all entities, organizations and corporate partners” involved in the Energy In Action network to disclose their funding sources and any financial connections to Canadian Energy Prosperity.

It is also echoing UN Secretary-General António Guterres’s call for countries to ban fossil fuel advertisements.

Methodology+

The presentations and agendas for two “Canadian Energy Prosperity funders” meetings, one in mid-2025 and one in early 2026, were posted publicly on the Energy In Action website, energy-in-action.com. The contact email listed was hosted on the domain cep-eia.com, a combination of the acronyms for both Canadian Energy Prosperity and Energy In Action.

The Narwhal reviewed the material directly by downloading it from the Energy In Action website on Oct. 2 and Oct. 5. The Narwhal emailed questions to Energy In Action’s email on Oct. 5. The following day, the Energy In Action website became password protected. Energy In Action did not return the request for comment.

One of the documents mentioned in this article included reference to a handful of philanthropic organizations, several of which have provided funding to The Narwhal and are disclosed on our website along with all major donors. Greenpeace carried out its investigation with support from the Trottier Family Foundation, which also provides funding to The Narwhal. As per The Narwhal’s editorial independence policy, no foundation has any editorial input.

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There was a brief, telling moment when Prime Minister Mark Carney was onstage at a Calgary Chamber of Commerce event last year, following the announcement of a memorandum of understanding with the Alberta government for a new “private sector constructed and financed pipeline” to the West Coast. 

Deborah Yedlin, the CEO of the chamber, mentioned the agreement’s stipulation: the project needed a private proponent rather than public funding. Then she said the project required “derisking.”“Are you saying there’s no room for the government to derisk something for a period of time in order to attract private capital that’s needed for a project like that?” she asked Carney. In other words, how far was Carney willing to go to protect industry from losses?Carney listed off moves his government was making, including regulatory clarity, tax incentives and loan guarantees to move the project forward. And then he said: “In essence, the Asian pipeline will be a private sector project …”

That one word, essence, bore considerable weight. 

So too did the timing of the Oct. 1 announcement that the pipeline — now known as Pacific Link — would be the first project of national interest listed under the federal government’s sweeping Building Canada Act. It comes just over two weeks before Alberta holds a referendum on whether to hold an independence referendum, as well as a slew of questions aimed mostly at immigrants. 

From the beginning, the pipeline plan was a political one, based on a calculus that can be hard to understand outside of Alberta, where decades of government and industry messaging has succeeded in tightly weaving oil and gas into the province’s culture. 

Never has that narrative been pushed harder than by the United Conservative Party government, first under former premier Jason Kenney and now amplified even more under Premier Danielle Smith. 

Having directly linked the future of the country with deregulation for the oil and gas sector, Smith now faces the headwinds of that rhetoric in the form of a burgeoning separatist movement. It’s one she has aided to protect herself from an influential secessionist base in her party. 

It’s a situation Carney has recognized and attempted to shape, acquiescing to Alberta’s demands in an effort to shore up a united front as threats from the United States grow more stark. 

The prime minister might have promised Canadians a “private sector constructed and financed pipeline” in last fall’s memorandum. But it was clear from the beginning he was willing to pay a premium to achieve peace. 

How Alberta’s politics of wealth and alienation fuelled the Pacific Link promise

After their first meeting in March of last year, Smith threatened Carney with an “unprecedented national unity crisis” if he did not respond to a list of demands almost entirely focused on boosting the oil and gas sector. 

It was part and parcel of a wider campaign to link Alberta’s political and economic fortunes more tightly with fossil fuels, including moves to designate emissions data as critical infrastructure to prevent the federal government from accessing it and put up regulatory and economic hurdles to block renewable energy development. 

Smith’s actions are part of a long history of resentment that stretches back as far as the creation of the province, when the federal government denied Alberta control over its natural resources, a move that was later reversed. 

There’s an entire mythology of eastern Canadian domination built up around the National Energy Program introduced by Pierre Elliot Trudeau in the early 1980s, which still resonates with separatists and mainstream conservatives alike. In this century, the climate actions of his son Justin Trudeau inflamed a new sense of subjugation in the oil patch. 

Those resentments and mythologies have been curated by successive Alberta governments as an easy way to rally Albertans to their cause and help cover up internal failures, particularly when it comes to budget crashes. And now it has reached a fever pitch. 

Carney, a veteran of Brexit and big brain amidst big brain money makers, recognized the weight of Smith’s threat and an especially restless Alberta, particularly as the geopolitical landscape shifted under his feet. He wasted no time in wooing her, and her province. 

He has proven willing to deregulate and slash emissions programs and targets to help industry. Now, he’s opening the federal government’s hefty purse to buy peace. The pipeline will cost billions, without any promise that price will be enough to please Smith’s government and the powers it has unleashed. 

Pacific Link pipeline promise is rushing to meet a very specific moment

Pacific Link is moving fast, because it’s meant to meet this specific moment: oil prices are high, Alberta separation is occupying vital political real estate, and a trade war with the U.S. is both threatening Canadian well-being and galvanizing political will for big risks and fast action. 

In this rush, it’s easy to lose sight of the fact that many important details still aren’t finalized — such as the route, financing and oilsands companies meeting requirements for a massive carbon capture and storage project.

All of this makes meeting this specific moment difficult, to say the least. It will be years before the pipeline is online. 

There are also serious questions about investing billions of taxpayer dollars into a project for a sector facing possible reductions in demand and a global shift away from the uncertainty of oil markets. Not to mention concerns over the impacts of increased emissions and the reduced ambitions for carbon capture. 

Despite this announcement, the referendum will still take place. The provincial government is spending millions to tell Albertans to send Ottawa a message and stand up for a more sovereign province. Its list of demands remains, even if Smith is playing nice with Carney for the time being.

The willingness of the Alberta government to act in good faith is also questionable. Only days after it signed last fall’s memorandum with the federal government, it went ahead with changes which undermined its industrial carbon price that it promised to strengthen in the agreement. 

That’s the same memorandum containing the broken promise of a “private sector constructed and financed pipeline.” It all suggests Donald Trump isn’t the only Western leader who signs agreements in pencil. 

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LNG Canada is already the largest liquefied natural gas (LNG) facility in the country. Now, the Shell-led project is set to double its production. 

The consortium of companies behind the massive LNG export facility announced the decision to green-light spending on Sept. 28. Shell, along with its partners Petronas, PetroChina, Mitsubishi and Korea Gas, were originally approved by the provincial and federal governments to build two phases of the Kitimat, B.C., plant in 2015. Operations of the initial phase started last year, with the first shipments leaving Canada in late June.

Prime Minister Mark Carney touted the investment decision in Vancouver this morning. “Canada is building big again,” he said, speaking to a room of company executives, politicians, First Nations elected and hereditary chiefs, municipal leaders and stakeholders. “Today’s investment — as you know, over $30 billion in LNG Canada 2 — will make LNG Canada the second-largest facility of its kind in the world.”

“This is a very big deal indeed,” BC NDP leader David Eby said at the same announcement. “It will change lives, here and around the world.”

The $33 billion investment decision comes as the first phase continues to face problems with its equipment.

As first reported in The Narwhal, an integrity issue with the facility’s flare stack was identified in the early commissioning stage after the company began testing its equipment in late 2024. LNG Canada later reported the problem to the BC Energy Regulator and the facility has been continually in non-compliance with its government-issued permits since. For months, Kitimat community members were subjected to excessive noise, black smoke, a towering flame — at times reaching the height of New York’s Statue of Liberty or London’s Big Ben — and a concoction of unidentified chemical smells and various other emissions as plant operators tried to get things under control. 

LNG Canada and the BC Energy Regulator maintain emissions from the plant are not harmful to human health, but many residents worry the combined output from the new liquefaction facility and Kitimat’s aluminum smelter may impact respiratory conditions and cause other health issues.

Burning excess methane gas, or flaring, is a normal safety procedure at liquefaction facilities. It releases greenhouse gases like carbon dioxide as well as emitting dangerous pollutants such as sulfur dioxide and small particulate matter, which affect human health.

Earlier in September, LNG Canada held community meetings in Kitimat so locals could weigh in on plans for a permit amendment. The consortium wants an increase in allowable emissions levels to account for its need to keep the flare burning 24/7 — until the stack can be redesigned in 2028. 

“There is an operational issue with the flare design where at very low flow rates, the gas being burned moves from the tip of the flare to within the flare tip itself, causing a hot spot in the metal there,” Teresa Waddington, a senior executive at LNG Canada and registered professional engineer, previously told The Narwhal. “To prevent these hot spots, more gas is sent through the flare system … to push the flame back up to the top of the flare tip.”

This “assist gas” amounted to around 10 per cent of all gas that was sent to the coastal plant last year. As The Narwhal and Point Source reported, LNG Canada flared 350 million cubic metres of gas in 2025, making it one of the highest sources of LNG flaring emissions globally.

What exactly is the LNG Canada Phase 2 expansion?

LNG Canada was approved for two phases: the second adds two processing units, called trains, to increase the liquefaction capacity from 14 to 28 million tonnes of LNG per year. This expansion also means Coastal GasLink, the contentious 670-kilometre pipeline supplying the export plant, needs to double its capacity. That will be done by building five new compressor stations along the route. 

“Thanks to LNG Canada’s decision today, TC Energy is moving forward with its own multi-billion-dollar Phase 2 of the Coastal GasLink pipeline,” Carney said. “That means doubling capacity, creating an additional 2,000 jobs and maximizing the value of … one of the most prolific natural gas basins.”

Coastal GasLink, which was built between 2019 and 2024 by Calgary-based TC Energy, faced widespread opposition in support of Wet’suwet’en Hereditary Chiefs, who argued the company did not receive free, prior and informed consent from the Aboriginal title holders to land intersected by the pipeline.

When Indigenous land defenders and their supporters tried to stop construction, a series of infamous RCMP raids led to dozens of arrests and solidarity protests across the country.

In its announcement yesterday, LNG Canada noted the investment decision includes an equity option agreement secured this summer with “a limited partnership of the economic development organizations of five First Nations neighbouring LNG Canada’s operations: Gitga’at Nation, Gitxaała Nation, Haisla Nation, Kitselas First Nation and Kitsumkalum First Nation.” That agreement “represents one of the largest Indigenous ownership positions in major Canadian infrastructure,” according to the company.

LNG Canada also said the expansion has “the potential to generate more than $50 billion in government revenues” over the 40-year life of the project.

“A year ago, the federal government referred LNG Canada Phase 2 to our Major Projects Office. One office. One point of contact. One goal: get to the right decision, rapidly and efficiently,” Carney said. “Working with Shell and LNG Canada, British Columbia, and First Nations, we have accomplished exactly that.”

What comes next?

Construction on the pipeline and at the Kitimat facility will begin immediately, Carney said in his speech. According to the company, around 4,000 workers will be hired to build the expansion at the plant and around 2,000 people will build the pipeline compressor stations.

Community members in Kitimat continue calling for transparency and investment in health facilities and studies. 

“I wish that they could acknowledge [emissions from the plant] could be a problem,” one young resident, who asked not to be named, told The Narwhal. “We’re gonna have to be around the flaring either way.”

LNG Canada said a redesign of the malfunctioning flaring equipment will be implemented in 2028. In the meantime, the company plans to request an amendment to its permits to account for continued higher levels of flaring emissions. 

The BC Energy Regulator said “LNG Canada has reported ongoing instances where flaring from one or more of the facility’s flare systems is not consistent with the requirements of its air discharge permit to the [regulator, but] these instances have not had a measurable impact on local air quality.”

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As the September sun dips down towards the mountains on the western side of the Kitimat Valley in northwestern B.C., a blueish haze hovers over the coastal community. 

The familiar plume from Rio Tinto’s aluminum smelter, a source of local air pollution for more than seven decades, now mixes with emissions from the LNG Canada gas liquefaction and export facility, which started shipping cargoes overseas last year. At the centre of the sprawling industrial site, an orange flame glows continuously from the top of a red and white tower. That’s the flare stack, which earned the new gas plant the dubious distinction of being among the world’s highest sources of flaring emissions last year. 

LNG Canada, owned and operated by a consortium of five foreign companies led by Shell, maintains its emissions are safe. Some residents aren’t so sure.

At open-house events at the town’s recreation centre over two days in mid-September, company executives, engineers and other employees field questions from members of the public. Moments after walking into the fluorescent-lit room, I’m recognized by a company representative who asks if I plan to interview anyone while I’m there. I laugh, shaking my head incredulously. He grins and says he’s read my reporting. A few minutes later, Teresa Waddington, a senior executive at LNG Canada and registered professional engineer, approaches to shake my hand.

LNG Canada is holding the event so community members can weigh in on plans for a permit amendment. The consortium wants an increase in allowable emissions levels to account for its need to keep the flare burning 24/7 — until the stack can be redesigned in 2028. 

Waddington tells me it’s not a perfect solution to problems that have plagued the flaring system since commissioning began in late 2024, but says the company has made significant progress to reduce flaring levels over the past couple of months. She says the original permit didn’t account for “higher flaring volumes” associated with getting an LNG plant up and running. 

But that’s not the whole story.

Kitimat sits at the end of a 100-kilometre long fjord, hemmed in by mountains. Its geography means the town experiences a specific set of weather conditions: regular high winds, temperature inversions, rollercoaster pressure systems fed by the Pacific Ocean and more. LNG Canada’s flare stack wasn’t built to handle those conditions.

When the liquefaction facility fired up its flare stack, locals and workers alike quickly realized something was wrong. As first reported in The Narwhal, an integrity issue with the main stack was identified and later reported to the BC Energy Regulator. For months, the community was subjected to excessive noise, towering flames lighting the night sky, black smoke and a concoction of unidentified chemical smells and various other emissions as plant operators tried to get things under control. 

“There is an operational issue with the flare design where at very low flow rates, the gas being burned moves from the tip of the flare to within the flare tip itself, causing a hot spot in the metal there,” Waddington tells me later in an email, after I follow up on our conversation. “To prevent these hot spots, more gas is sent through the flare system … to push the flame back up to the top of the flare tip.”

This “assist gas” amounted to around 10 per cent of all gas that was sent to the coastal plant last year. Locals nicknamed the flare, which reached heights of around 90 metres at times, the “Eye of Mordor” after J.R.R. Tolkien’s The Lord of the Rings.

While LNG Canada is working to amend its permits, the consortium also appears poised to make a final investment decision on an approved expansion, which would double production at the Kitimat plant. As Reuters recently reported, a decision on the project’s second phase could come as early as October. Both the federal and provincial governments have signalled strong support for the expansion.

In the community, vast work camps built to support construction of the LNG plant sit vacant and quiet. Today, the flare burns low, a dull fiery glow at the heart of the haze like the ember of a cigarette seen across a dimly lit room. It’s been calmer and quieter lately — but problems persist, and the gas being burned daily continues to exceed government permits.

Flaring not a danger to human health, LNG Canada says

Kitimat is no stranger to industry. The community was built on Haisla lands in the 1950s as a company town — serving what was then known as the Aluminum Company of Canada, or Alcan. 

The town’s residents, while not accustomed to living alongside a liquefied natural gas plant, are familiar with being an industrial hub. As Kitimat mayor Phil Germuth previously told The Narwhal: “Being a town that was built by industry, people understand that every once in a while you’re going to have to put up with something to get the bigger goal in the end.” 

Kitimat is also a small town, with a population of around 8,000, and a major industry like LNG Canada has extensive connections throughout the community that might make dissenting residents think twice about openly voicing their opinions. 

Several community members The Narwhal spoke to, who asked not to be identified, said they’re grateful for LNG Canada grants they’ve received or sponsored programs they’ve participated in, but worry about how the combined emissions from the two major industrial facilities might be affecting their health. Most who shared their views say they’re not against having a gas plant in town — but they’re skeptical about claims the emissions aren’t harmful.

One resident tells me they avoid strenuous activity outdoors now — just in case. Another, who owns and operates a local business, wonders why Rio Tinto, which produces more hydroelectricity than it uses and sells the balance to BC Hydro, and LNG Canada, which is liquefying natural gas extracted from deposits in the northeast, don’t provide the town with free electricity and gas.

“I’d much rather not pay for hydro and gas,” they shrugged.

According to LNG Canada and the provincial regulator, excess flaring isn’t a problem for human health. Because the gas is burned at the flare stack, it’s mostly converted to carbon dioxide and water vapour, Waddington says. In other words, more gas being flared doesn’t necessarily increase local pollution levels — which have remained below provincial guidelines, according to the BC Energy Regulator. This claim is substantiated by local air quality monitoring, much of which was implemented when Rio Tinto underwent a major expansion between 2011 and 2015.

“There is a long-established air quality monitoring network that monitors ambient air quality in the Kitimat region, on an ongoing basis … to ensure no impact to human health,” Waddington says.

They’ve reduced the flaring volumes significantly since installing a new flare tip in July, Waddington adds, but until the whole system can be redesigned they will still need to burn more gas than originally planned.

The new flare tip has “the same design [with] upgraded metallurgy [that enables it to] operate with a bit more backburn and manage hot spots,” which she explains reduces the amount of extra gas being flared by about 60 per cent. “We are working with the company that designed the flare tip to improve this design further and to ensure it operates as expected in real-world conditions.”

But there are other emissions from the plant, too, including black smoke from the stack, which indicates particulates and unburned gases. As The Narwhal recently reported, LNG Canada predicted black smoke would be emitted between 15 and 60 minutes one to three times per year while it stabilized early operations, but the plant has exceeded that estimate. 

In April, the BC Energy Regulator ordered LNG Canada to identify the root cause and implement a fix by October. On Sept. 21, the regulator posted the first report since implementing these measures, which identified “20 black smoke events that occurred between April 22 and July 31, 2026, including events that LNG Canada self-reported as non-compliances.” The regulator noted LNG Canada also reported “four additional black smoke events during August 2026” and community members told The Narwhal of at least one event in September.

Still more types of emissions, visible only through an optical gas imaging camera, are also being released at the plant. Details of these emissions were published in August by The Narwhal and Point Source after being observed by Tim Doty, a former oil and gas inspector with the state of Texas.

“The emissions that could not be seen with the bare eye were shocking,” he said at the time, after monitoring emissions at the Kitimat facility with a camera earlier in the year.

In Strawberry Meadows, the residential neighbourhood closest to the plant, several homes and serviced lots are listed for sale. They’re nice houses: modern design, tucked in amongst the trees on quiet streets. But while the entire town is adjusting to living with the new industrial project, it’s this area that has experienced the most noise and emissions. 

Around this time last year, one resident of the neighbourhood told The Narwhal he and his family couldn’t sleep for days on end.

“We maybe got two hours’ sleep this whole weekend. I’m just useless now.” 

Because of the imminent provincial election, the regulator was unable to answer questions, noting “government is in a caretaker mode” and communications, including from Crown agencies like the BC Energy Regulator “are limited to critical health and public safety information.” A spokesperson sent links to data — LNG Canada’s daily and monthly flaring amounts, the latest air quality data map and B.C.’s air quality objectives and standards — along with a statement about its ongoing oversight of the liquefaction facility.

Residents ‘more curious than concerned:’ LNG Canada executive

At the open house, community members speak quietly with company reps, asking questions about flaring, emissions, smells and more.

Joanne Spencer, another senior executive with LNG Canada, says most residents who come through are more curious than concerned. Between four sessions over two days, around 120 people stop by.

“This is quite an engaging way to talk to members of the public,” she says, gesturing around the room at clusters of employees speaking with residents. “If you’re looking at somebody in the eyes, it gives the opportunity for you to acknowledge that they’ve understood or [see if they] have another question.”

For her part, Waddington says she’s committed to show up at council meetings and “many other places where people congregate to engage in the conversation on what LNG Canada is doing well and where we need to improve.” 

She tells me she previously worked as a plant manager at a Shell gas facility in Scotland where flaring “attracted community interest and concern.”

“As a result of a prolonged flaring incident, many of the staff from the facility were facing hard questions from concerned community members in their day-to-day lives,” she says, explaining she experienced tension while going about the community. 

“It was important to me then, as it is to both me and LNG Canada now, that the company engages directly with [the] community when they have concerns to provide information, listen for what matters and how we can improve in those areas or better communicate about them.”

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As other western provinces struggle to address the environmental and economic fallout from thousands of orphan oil and gas wells, only a tiny portion of Manitoba’s petroleum infrastructure is sitting idle and unclaimed. 

But it’s unclear, however, if the province’s small roster of orphan wells is the byproduct of effective regulation — or a historic lack of departmental oversight. Manitoba’s oil and gas industry is relatively small and generally opaque. None of the experts contacted for this story had direct knowledge of the province’s orphan-well landscape.

“My lab has probably measured the most non-producing wells in the country. I don’t think anybody I know is working on it [in Manitoba] who are in the academic realm,” Mary Kang, an associate professor in civil engineering at McGill University, says.

The province’s petroleum branch has only been compiling and sharing orphan-well data for the past five years. Its 2025 inventory lists 31 well sites without a legally or financially responsible owner, which make up less than one per cent of the 4,000 wells currently producing oil in Manitoba.

The reasons for this are many: Manitoba’s oil and gas industry is smaller than other western provinces, allowing for regular inspections of batteries and most producing wells, according to an emailed statement from a provincial spokesperson.

But the intricacies of regulation also differ across the provinces. At the same time, the government body tasked with keeping tabs on the issue has been chronically understaffed. Whether Manitoba offers a lesson for other provinces or if it should be eyeing the rapidly escalating orphan well inventories of its neighbours with caution remains to be seen.

Environmental impacts of old wells can include methane, contamination

Orphan wells are oil or gas drilling sites that have been left to languish without being properly cleaned up, often because the company that owns them has gone bankrupt. Wells are often thousands of metres deep and these sites can leak methane, a potent and volatile greenhouse gas, and contaminate soil, air and groundwater.

A 2025 study co-authored by Kang suggests Canada’s non-producing oil and gas wells emit a combined 230 kilotonnes of methane per year — a figure seven times higher than estimates from Environment and Climate Change Canada. Wells that have been properly sealed with cement and decommissioned are referred to as plugged or “abandoned.” Most orphan wells are not yet plugged.

“In general, plugged wells emit less [methane] and are less of an environmental concern,” Kang says, adding unplugged wells are a bigger concern. “But even among unplugged wells, some emit nothing and some emit a lot.”

Orphan well inventories can grow ‘in leaps and bounds’

Orphan wells are an issue that can expand quickly.

“The concern is that the inventory can grow in leaps and bounds from year to year. We just saw that happen here in Alberta,” Amanda Bryant, manager of the oil and gas program at the Pembina Institute, an Alberta-based environmental think tank, says. 

Alberta’s orphan-well inventory ballooned to more than 7,300 sites this year after thousands of wells owned by an insolvent Calgary-based oil company were transferred to the province’s Orphan Well Association.

The association — a non-profit funded by industry — is responsible for decommissioning and cleaning up orphan oil and gas sites. Alberta had fewer than 300 orphan wells when the organization was founded in 2002.

That exponential growth is due to poor provincial regulation, Bryant says. 

“The main problem is that there’s nothing stopping companies from deferring the costs of closure and cleanup,” she says. “The other half is the so-called liability-dumping behaviour that a lot of companies engage in.”

The practice of liability dumping cited by Bryant has made insolvency a growing concern as larger companies sell off risky assets to smaller companies, which critics say happens with too little financial vetting from the regulator.

As in Manitoba, oil and gas companies in Alberta are legally required to clean up well sites that are no longer in use. Yet, because the Alberta Energy Regulator provides no concrete timelines for closing unused wells, operators often leave the sites for years or decades to avoid paying clean-up costs. 

If a company files for bankruptcy prior to remediation, that cost is passed on to the Orphan Well Association. Taxpayers can be left footing some of  the bill for closure costs — which carry an estimated $1.66-billion price tag — due the association’s lack of adequate funding, while also covering delinquent oil and gas companies’ unpaid oil and gas land rent and taxes owed to municipalities.

To address the issue, the Pembina Institute has recommended increasing the orphan-well levy, enacting an escalating inactive-well fee and introducing strict timelines for cleanup.

The situation is similar in Saskatchewan, which has nearly 4,500 orphan wells, and British Columbia, which has 998.

Manitoba’s unique regulatory environment

Manitoba’s oil and gas industry is an outlier in several ways. 

For one, it has a comparatively small oil patch, which is concentrated in the southwest corner of the province and dominated by Tundra Oil & Gas — a locally owned subsidiary of James Richardson & Sons. 

It also differs in provincial regulation. Operators have to submit an application to suspend drilling at a well site to the petroleum branch. Suspensions are valid for a maximum of three years, after which the company needs to apply for an extension.

“What it means is that Manitoba has a much lower proportion of its wells that are in a suspended state,” Bryant says. “If [wells] sit there in a state of inactivity for a long time … there’s a risk that they’ll end up orphans, and so that’s a positive policy move that the province has taken.”

Unlike other provinces, where insolvency is a driving force, most of Manitoba’s orphan wells are the result of petroleum branch seizures following non-compliance of shutdown orders or failure to meet regulatory requirements, a provincial spokesperson said. 

If a seized well is capable of producing oil, the province can sell the facility or transfer the licence to a new owner.  

Nearly all of the companies with orphan wells are still actively drilling elsewhere in the oil patch.

Four inspectors are now employed in Manitoba’s petroleum branch, up from one

Manitoba has been addressing orphan wells for many years, according to the province, but only released its first consolidated inventory in 2021, with an update posted publicly last year. 

Of the 23 wells listed on the original inventory, all but six remained orphaned in 2025, according to a Narwhal/Free Press analysis of the publicly available records. The others were removed from the list after their status was updated to abandoned (as in, properly plugged) in 2022.

The 2025 batch of 25 seized wells is largely due to improved staffing capacity, allowing the department to clear a backlog of investigations, the spokesperson said.

Manitoba currently has four provincial petroleum inspectors, up from the single inspector employed in early 2024, when a major Imperial Oil pipeline shutdown prompted the government to address gaps in its monitoring program.

Mya Wheeler, a Winnipeg-based social scientist and researcher whose PhD thesis focused on the local oil and gas industry, found staffing was a perennial problem that undermined departmental efforts to adhere to legislated regulations. 

“As the ramping up of oil wells occurred, there was the same and then less staff, and there was a 600 per cent increase in drilling during the fracking boom,” she says.

“There’s not a lot of ability to make compliance happen because of low staffing.”

Eva Wasney is a reporter covering environmental issues in Manitoba. Her position is part of a partnership between The Narwhal and the Winnipeg Free Press.

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