Naheed Nenshi, the NDP leader of Alberta’s Opposition, is accusing Premier Danielle Smith of a scheme that could increase power bills for Albertans “so she can build AI data centres for her foreign billionaire friends.” 

The comments come from a news conference organized by the NDP in response to reporting by The Narwhal on a leaked document — labelled a “cabinet report” and bearing the Alberta government logo — that appears to show the provincial government is planning to take control of Alberta’s natural gas pipeline system to increase both supply and demand. 

The document outlines plans to wrest regulatory control over the province’s main natural gas transmission line, called the Nova Gas Transmission pipeline, owned and operated by TC Energy, away from the federal Canada Energy Regulator, and to create two new government-owned corporations. One of those Crown corporations could force companies to build natural gas pipeline expansions based on government priorities, while the other could build and operate the pipelines itself. 

Those moves, according to the document, would raise prices on ordinary Albertans and businesses, but would bring in more royalties for the government. 

“Let me reiterate this: Danielle Smith is rolling out the red carpet for data centres, and that will cause higher electricity prices, and she doesn’t care if it spikes your electricity and your heating bills,” Nenshi said.

Detailed questions were sent to several Alberta ministries prior to publication of the original story, but the government did not respond by publication time. 

Late Friday afternoon, the office of Minister of Energy and Minerals Brian Jean sent a statement to The Narwhal in response to a follow-up email asking for comment on the original story.

“Governments routinely examine a wide range of policy, regulatory and legislative options when considering complex issues, and internal materials do not represent government decisions,” it said.

“An increasing number of project proponents across a variety of industries have raised concerns about accessing industrial quantities of natural gas in several regions of Alberta. We are working with industry, including the natural gas infrastructure owners, to better understand these issues and identify practical solutions that support future growth and investment.”

The document on which the reporting was based was leaked to The Narwhal by a source within the Alberta government, whose identity is being kept confidential due to personal and professional risks stemming from the leak. 

A note on trust, integrity and unnamed sources+

This story uses information from sources The Narwhal has agreed not to name. The Narwhal only agrees to keep names confidential when we believe two things. First, that the person we’re speaking with is putting themselves at genuine risk, either personal or professional, by sharing this information with us. Second, that the information they’re sharing is in the public interest. Our decision to do so is never made lightly. 

There are two types of unnamed sources. A confidential source is someone whose name we know, but aren’t sharing. We make multiple attempts to verify their identity and information with other sources. If we aren’t able to get a second source, we say so. 

An anonymous source is someone whose name we don’t know. It is incredibly rare for The Narwhal to publish a story with a completely anonymous source. In these instances, we don’t publish until we have verified the information shared with us with at least one other source. 

And again, these stories must be in the public interest. 

As Canadian governments become increasingly secretive, the courage of whistleblowers is to be admired. We value them greatly. At the same time, our promise to readers is The Narwhal will always make sure the facts are airtight. 

Have something to share? Send us a story tip.

The moves could cost billions of public dollars if the government builds its own pipelines, according to the document. The document estimates it will cost more than $160 million just to institute the changes and fight anticipated legal battles with companies such as TC Energy, or potentially First Nations. “There may also be litigation risk from Indigenous communities and organizations where they believe that they have not been meaningfully engaged from early on in any proposed projects,” the document reads.

Sturgeon Lake Cree Nation Chief Sheldon Sunshine said his community, which is fighting a massive data centre proposal in northern Alberta led by celebrity investor Kevin O’Leary, is “outraged” by the details outlined in the document, which he says he has independently reviewed.

“For years, our Nation has been fighting for meaningful consultation and effective regulation of hyper-scale data centres — including the massive O’Leary Project,” he said in a statement sent to The Narwhal. Sturgeon Lake Cree Nation is not specifically named in the leaked document.

“Now we find out that the United Conservative Party government is trying to artificially drive up the demand for natural gas to lure even more of these data centres to Alberta — all while knowing that this would trample our Treaty Rights and send electricity prices soaring for all Albertans.”

The document estimates building a pipeline to meet government expectations could cost as much as $6 billion. The capacity from that new pipeline could provide enough gas for six gigawatts of power generation for data centres, according to the document. A recently rejected AI data centre near Olds, Alta., would have required a 1.4-gigawatt power plant and used as much power each day as the City of Edmonton.

According to information on TC Energy’s website, the company has invested approximately $15 billion into the Nova Gas Transmission system since 2015, with double the capacity increases outlined in the document.

The document points to the need to feed natural gas to AI data centres as a primary motivation for the moves, but also highlights desired growth in the oil and gas sector, saying “the Government of Alberta is actively courting hyper-scale data centre capital and other investors.”

Nenshi, who said he has now seen the leaked document himself, was blunt. 

“This report makes it clear that their strategy all along was to do whatever they could to increase natural gas prices, to promote the government’s own bottom line due to their own fiscal mismanagement,” he said. The document suggests the moves could increase royalties to the government while consumers could end up paying higher prices for their natural gas and electricity bills under the proposed plan.

Document leaked by whistleblower for whom Canada affords little protection: expert

According to David Hutton, a senior fellow with the Centre for Free Expression at Toronto Metropolitan University, whistleblowers who leak sensitive information to the media run a considerable risk, from losing their jobs, friendships or families through divorce.

He said Canada is “back of the bus” when it comes to protections.  

“International experts have done surveys of various countries and rated them, and we come out at the bottom,” he said in an interview. The federal government has a whistleblower program, but Hutton said there’s never been compensation awarded through it. 

Provincial laws are similar to the federal protections, including Alberta’s, and “are really not of any value,” he said. 

He stresses how crucial it is for public-interest information to see the light of day. As The Narwhal has reported, this is becoming increasingly difficult in Canada as multiple levels of government tighten freedom of information legislation. 

“Research done over decades now has consistently shown that tips from whistleblowers account for usually more than 40 per cent of all of the frauds that are uncovered [globally],” he said, highlighting one aspect of information that is shared.

There is no indication of fraud in the leaked document in Alberta. 

The plans outlined in the document single out TC Energy, which owns and operates the largest gas pipeline system in the province, as a likely source for legal action pushing back against the plans, due to the impacts on its business. 

The company did not respond to questions for the original article or for this follow up. 

Nenshi said he has not yet spoken with representatives from the company after the revelations were made public, but intends to. 

“To actually say government wants to step in in order to hurt people, and that government is strong-arming a company to make billions of dollars in investments that they don’t want to make, with the threat of competing with them if they don’t?” he said. “That’s textbook bullying behaviour. It’s also bad economics and it’s bad business.”

Document points to constraints imposed by feds, says Alberta seeks to ‘achieve greater control’

The document points the finger not just at TC Energy, but also at constraints imposed by the federal regulation of the natural gas transmission network.

“Federal regulatory oversight … is now compounding Alberta’s gas access challenges,” the document reads, adding this oversight “has caused growing concern about the pace of infrastructure development for the [natural gas transmission network].”

The document suggests moving TC Energy’s Alberta pipelines back under provincial regulatory control and under the authority of one of the new government corporations.

Some pipeline networks within the province are already under provincial jurisdiction, including the ATCO distribution network that interconnects with TC Energy’s system. ATCO operates approximately 8,500 kilometres of pipelines in Alberta, whereas the Nova Gas Transmission pipeline, the province’s main natural gas transmission line operated by TC Energy, is about 25,000 kilometres.

“Without provincial regulatory oversight, the Government of Alberta is limited in its ability to compel federally regulated pipelines to invest in capacity expansions,” reads the document.

“Due to the federally regulated [natural gas transmission line] system being fully subscribed, the province cannot guarantee the timely expansion of gas transmission capacity required to support new demand.”

Have something to share about Alberta’s push for more data centres and oil production? Send us a story tip.

The Narwhal’s reporters are telling environment stories you won’t read about anywhere else. Stay in the loop by signing up for our free weekly dose of independent journalism.

Editor’s note: Go here to read The Narwhal’s story on the backlash that followed this investigation.

Alberta is so determined to usher in a wave of AI data centres and increase oil and gas production that it is considering rewriting legislation and creating government-owned corporations that would force private companies to invest in natural gas pipeline expansions — or allow the government to build and operate those pipelines itself — according to a document leaked to The Narwhal. It’s also willing to pay for any legal challenges that follow. 

The document — labelled a “cabinet report” and bearing the Alberta government logo — contains a broad swath of recommendations it indicates were prepared for the Energy and Minerals Ministry led by Minister Brian Jean, and says it was scheduled to be presented to a high-level cabinet policy committee on Sept. 10.

The document says private ownership of natural gas transmission pipelines is throttling growth and that “escalatory and direct measures are now required,” especially as “the Government of Alberta is actively courting hyper-scale data centre capital and other investors.”

The document notes Alberta risks losing investment from AI data centre companies if it can’t come up with “speed-to-market” solutions.

According to the document, the government has been in talks with TC Energy, which owns and operates Alberta’s main natural gas pipeline system, since 2024 in an attempt to force the company to invest in new pipeline capacity, but the company refuses to build based on “speculative demand.” TC Energy did not respond to detailed questions.

Talks with the company stalled, according to the document, after the company pitched a plan that would involve the province assuming more financial liability for the pipeline system and forcing higher rates on those who use it. 

“Discussions continued until 2026 and escalated with the premier’s involvement,” reads the document. “Extensive discussions with TC Energy [have] produced no viable solutions to date.”

The document is critical of TC Energy’s track record, saying the company’s “underinvestment in [natural gas] pipeline capacity has caused a market failure in the natural gas sector leaving key growth regions unable to access gas,” calling the result a “dysfunctional natural gas pipeline network.”

The document was leaked to The Narwhal by a government official whose identity is being kept confidential. The Narwhal has verified they are in a position that would likely have access to such a document. The Narwhal has not been able to independently verify the authenticity of the document, but Alberta’s lobbyist registry confirms TC Energy has been in talks with government officials regarding “increased support for gas market access,” as well as discussions on “strategic natural gas initiatives.”

A note on trust, integrity and unnamed sources+

This story uses information from sources The Narwhal has agreed not to name. The Narwhal only agrees to keep names confidential when we believe two things. First, that the person we’re speaking with is putting themselves at genuine risk, either personal or professional, by sharing this information with us. Second, that the information they’re sharing is in the public interest. Our decision to do so is never made lightly. 

There are two types of unnamed sources. A confidential source is someone whose name we know, but aren’t sharing. We make multiple attempts to verify their identity and information with other sources. If we aren’t able to get a second source, we say so. 

An anonymous source is someone whose name we don’t know. It is incredibly rare for The Narwhal to publish a story with a completely anonymous source. In these instances, we don’t publish until we have verified the information shared with us with at least one other source. 

And again, these stories must be in the public interest. 

As Canadian governments become increasingly secretive, the courage of whistleblowers is to be admired. We value them greatly. At the same time, our promise to readers is The Narwhal will always make sure the facts are airtight. 

Have something to share? Send us a story tip.

Detailed questions sent to the premier’s office, including for confirmation of details in the document, were sent to the press secretaries for the premier and the ministers of affordability and utilities, energy and minerals, jobs, economy, trade and immigration, and treasury board and finance. There was no response by publication time. 

There was also no response to an email and phone call to Vitor Marciano, the chief of staff to the energy minister.

According to the document, the full slate of proposals for cabinet consideration include taking regulatory control for the pipeline transmission network operated by TC Energy away from the federal Canada Energy Regulator, creating a Crown corporation that would guide pipeline construction based on government forecasting, and another Crown corporation that would oversee, or build and operate, its own pipelines. 

That would give the government the power to control some private investment decisions, including directing companies to build pipelines, and it could also make the government a direct competitor of companies such as TC Energy. 

The document argues the moves are necessary to rapidly build natural gas pipeline capacity to help increase oil and gas production and spur data centre growth. The government’s data centre strategy explicitly encourages the use of natural gas for power generation. 

Since the release of that strategy, the government has restricted AI data centre access to the provincial grid until 2028 because there is not enough power to fuel demand and keep the lights on. Developers are required to build their own power supply, which is currently restricted to natural gas power plants.

Albertans could be on the hook for hundreds of millions — or billions — to help support power for AI data centres: document

The moves could cost Albertans. 

The document is clear one of the main drivers of the plan, in addition to increasing the province’s oil and gas production, is attracting AI data centres to the province. “Alberta’s ability to attract and retain data centre investment depends on reliable access to natural gas service,” the document says. 

The recommended changes would result in “significant legal and cost impacts for the Government of Alberta,” according to the document, as well as likely result in “increases for utility ratepayers.”

The document notes Albertans may be “sensitive” to what it calls “any change in perceived affordability.”

The preliminary estimated cost of the proposed changes, including the planning and creation of Crown corporations and potential ensuing legal battles, could exceed $162 million, according to estimates in the document, but that does not include possible infrastructure costs.

The document estimates building a pipeline to meet government expectations could cost as much as $6 billion. The capacity from that new pipeline could provide enough gas for six gigawatts of power generation for data centres, according to the document. A recently rejected AI data centre near Olds, Alta., would have required a 1.4-gigawatt power plant and used as much power each day as the City of Edmonton.

The total cost includes anticipated litigation from TC Energy and other companies, including concerns over “significant claims for compensation” for “alleged expropriation of valuable contractual rights.” 

The document warns First Nations could also initiate lawsuits. 

The moves could also make things more expensive for residents and businesses by driving up the price of natural gas, according to the document.

“While low prices benefit customers (Albertans and industrial users), they limit provincial royalty revenues and can discourage natural gas investment by reducing producer revenues,” the document reads. 

“Increased natural gas demand could contribute to higher costs for households, businesses and gas-intensive industries, which could deflect stakeholder support.”

The document also notes “potential disproportionate impacts on seniors and rural residents can be mitigated by monitoring affordability and exploring mitigation measures specific to households and small businesses.”

The government’s aim is to almost double natural gas prices to support and expand production, which would increase the cost of electricity generation by up to 25 per cent, based on calculations in the document. 

It’s unclear exactly what that could mean for Albertans’ power bills, but those costs could be passed down to Albertans, who the document warns could be upset about government spending and increased costs. 

A recent analysis from the Pembina Institute, estimates the recently announced Meta data center near Edmonton could add $270 to $460 to electricity bills each year.

The document suggests government messaging could sell the plan to Albertans to “help strengthen social licence.”

Have something to share about Alberta’s push for more data centres and oil production? Send us a story tip.

The Narwhal’s reporters are telling environment stories you won’t read about anywhere else. Stay in the loop by signing up for our free weekly dose of independent journalism.

For over a decade, Enbridge Energy’s Line 5 has been the centre of a political and environmental battle in Michigan. The legal conflict included state officials, federal agencies, tribal nations, environmental groups and the Canadian energy company fighting over what the future of the aging pipeline should look like.  

But, in recent weeks, that debate has only become more complicated. 

Michigan’s Department of Environment, Great Lakes and Energy issued a key environmental permit for a proposed tunnel on July 15, appearing to move the project closer to construction. 

Two weeks later, the construction timeline moved farther away after the Michigan Supreme Court ruled that the Michigan Public Service Commission did not adequately consider the tunnel’s environmental consequences when giving the project its own permit. The court sent the case back to the commission for further review.

The decision added another layer to a dispute that already involved state and federal courts, multiple government agencies and competing arguments about Michigan’s energy needs, the Great Lakes and tribal Treaty Rights.

“We’re still in a state of limbo,” Mike Shriberg, director of the University of Michigan Water Center, said. “The decisions in the last few weeks, rather than clarify, have probably muddied the waters more and extended the lifetime of the conversation and the decisions about the future of Line 5.”

And on Aug. 12, the U.S. Army Corps of Engineers issued a long-desired permit for Enbridge for the construction of the tunnel. The next steps are securing the remaining permits and approvals needed for construction.

A long history

In 1953, Line 5 was built running 1,038 kilometres from Superior, Wisconsin, through Lake Michigan and Sarnia, Ont. Initially, the pipeline’s lifespan was supposed to be around 50 years. Its 50th birthday was 23 years ago. 

Most of the pipe is about 75 centimetres, with the exception of the position beneath the Straits of Mackinac. There, the pipe splits into two 50-centimetre lines that sit on the lake-bed for about seven kilometres.

That section has become the main bearer of controversy, with the central focus being a possible rupture that could release oil into the Great Lakes.

Safety concerns heightened after an approximately two-metre rupture in another Enbridge line, near Marshall, Michigan, in July 2010. The break released more than three million litres of heavy Canadian crude oil into Talmadge Creek and the Kalamazoo River.

In 2018, due to human error, a ship’s anchor hit Line 5 causing minor dents, but no oil was spilled. 

The proposed Great Lakes Tunnel Project would run beneath the lake-bed. Enbridge says the pipeline would sit about 30 metres below the lake-bed, protecting it from ship anchors. 

But the tunnel has yet to be built.

Why the debate is still ongoing

The newly proposed tunnel is only one piece of the larger Line 5 dispute.

In 2019, Michigan Attorney General Dana Nessel sued Enbridge in hopes of shutting down the existing pipelines in the Mackinac straits. She argued that Enbridge did not have a valid agreement to operate the pipeline under the straits — mainly that Line 5 was violating Michigan environmental laws.

This year, the U.S. Supreme Court ruled that Nessel’s lawsuit belongs in state court after Enbridge attempted to move it to federal court.

Separately, a federal judge ruled in December that Michigan could not enforce its 2020 order to shut down Line 5 — saying the federal pipeline safety laws overruled the state’s order. Since then, Michigan has appealed the decision.

The result is a series of overlapping cases moving through different courts.

“I think it’s mostly because the legal system that we have is set up to make it easier to delay than to move forward,” Shriberg said. “It’s pretty easy in our legal system to draw things out, to appeal, to stop things from happening.”

That’s why Line 5’s problems are difficult to summarize in a single legal storyline.

“It’s a complicated array of things going on that’s very hard to explain in a straightforward manner,” Shriberg said.

Enbridge’s case for keeping the pipeline

Through the last decade of controversy, Enbridge has maintained that Line 5 is an important part of the region’s energy infrastructure.

Ryan Duffy, an Enbridge spokesperson, said the pipeline carries light crude oil and natural gas liquids, with about 80 per cent of the products being light crude oil and 20 per cent natural gas liquids.

The company says Line 5 transports as much as 540,000 barrels of product each day, a figure also cited by the Michigan Public Service Commission. The company estimates that Line 5 supplies 65 per cent of propane demand in Michigan’s Upper Peninsula and 55 per cent of the state’s overall propane needs.

“A lot of people still heat their homes with propane in [Michigan’s Upper Peninsula],” Duffy said.

Line 5 is “at or near capacity,” Duffy said, adding that the only other pipeline moving product toward Sarnia is Line 78 which is also at or near capacity.

“There is really no viable alternative to transporting the product that Line 5 carries,” Duffy said.

Enbridge’s proposed solution to safety concerns is the tunnel.

According to Duffy, the tunnel was determined to be the best solution for protecting Line 5 in the Straits. He said the project would eliminate the possibility of oil or other products escaping into the Straits. 

Enbridge also points to the pipeline’s operating history. 

The company says the straits crossing has never leaked during more than 65 years of operation and is subject to continuous monitoring and maintenance.

Yet, Line 5 has experienced spills elsewhere along its route. In 2017, a National Wildlife Federation analysis identified 29 known spills, busts and equipment failures along the pipeline since 1968. Between those spills, more than three million litres of oil and natural gas have been released.

Concerns beyond safety

“The tunnel is really the common-sense solution going forward because it both protects the environment and makes sure that the product that people need continues to be delivered safely and reliably and affordably,” Duffy said.

For Bay Mills Indian Community President Whitney Gravelle, located in Michigan’s Upper Peninsula, Line 5 is not a question of safety or energy supply.

“For my tribal nation specifically, Line 5 is a threat to our way of life, to our tribal Treaty Rights, to our cultural resources,” Gravelle said.  

Line 5 crosses territory included in the 1836 Treaty of Washington, where tribal nations yielded millions of acres of property to the United States while retaining certain rights, including what the treaty describes as the “usual privileges of occupancy.”

Gravelle said those rights depend on the health of the natural resources around them.

“You can’t have a treaty right to fish without clean water for fish to spawn,” she said. “And you can’t have a treaty right to hunt if you’re cutting down forests and filling wetlands.”

Protecting the Great Lakes is inseparable from protecting the tribe’s culture for Bay Mills. 

“We cannot be Ojibwe, Anishinaabe, without the Great Lakes,” Gravelle said. “Our entire being, our culture, our language is interwoven into the Great Lakes.”

She says the tribe opposes the tunnel because it believes moving Line 5 underground would extend the pipeline’s operation rather than eliminate the threat. 

“We’re only focused on these four miles in the straits without looking at the 645 miles that Line 5 traverses and asking ourselves, 100 years from now, do we still want Line 5 in the state of Michigan?” Gravelle said. “Because that’s what the tunnel would do. It would cement Line 5’s existence for the rest of time.”

Others have raised similar concerns.

Jeffrey Insko, an English professor at Oakland University who writes a newsletter on Line 5, said the tunnel could lock in fossil fuel transportation for decades.

“What the tunnel really means is locking in fossil fuel transport for another 100 years,” Insko said.

For the tunnel, he said he is also concerned about whether the project would adequately protect the Great Lakes from environmental harm during construction.

“We need to be thinking about ways and investing in ways to reduce fossil fuel consumption rather than investing in prolonging the lives of fossil fuel consumption,” Insko said.

How needed is the pipeline?

At the heart of the disagreement is a key question: does Michigan need Line 5?

“The one thing that people haven’t looked into or covered enough is: What’s the need for Line 5?” said Shriberg of the University of Michigan. “There’s extremely good information out there that shows that Line 5 is not needed for use in the U.S.”

Enbridge says it is. Opponents say alternatives exist.

Gravelle said Enbridge should decommission Line 5 and instead use alternatives like using Line 78, which runs through southern Michigan from Indiana to Sarnia. She argues Michigan could continue getting energy supplies without Line 5. 

“This ultimately is about Enbridge’s profits. It’s not about energy infrastructure,” Gravelle said.

Over the years, the state should have used the time to reduce its reliance on fossil fuels, she said. 

“What could we have done in those 10 years to actually reduce our reliance on those issues?” Gravelle said. 

Enbridge disputes any claims that there could be other ways to supply what the line holds, saying there are no viable alternatives capable of replacing everything Line 5 currently carries.

What’s next

The immediate future of the Great Lakes tunnel is uncertain.

The Michigan Supreme Court’s July 31 decision requires the Michigan Public Service Commission to revisit its analysis of Enbridge’s tunnel proposal — which includes the environmental impacts that the court said were not adequately considered.

“The Great Lakes tunnel is on sort of an indefinite hold right now,” Shriberg said. “There’s not going to be any dirt moving in the near future.”

Duffy said the decision is disappointing and delays a project the company has spent years planning and permitting.

“We view that as disappointing because that is going to be an additional delay,” Duffy said.

The U.S. Army Corps of Engineers has also issued a federal permit for the tunnel project, adding another approval to the project’s permitting process.

At the same time, the legal battle over whether the existing Line 5 pipelines can continue operating in the Straits remains separate from the tunnel permitting process.

“They’re on separate tracks,” Shriberg said.

The goal remains clear for Enbridge: keep Line 5 in operation and move the straits crossing into an underground tunnel.

After more than seven decades, the pipeline remains in operation. And after years of lawsuits, reviews and political battles, the question of what happens to Line 5 is still unsettled.

“I would not expect any final decisions on a Great Lakes tunnel until 2027 at the earliest,” Shriberg said.

For now, the pipeline continues to carry petroleum through the straits while the courts and regulators decide whether its future lies beneath the water, inside a tunnel, or somewhere else entirely.

The Narwhal’s reporters are telling environment stories you won’t read about anywhere else. Stay in the loop by signing up for our free weekly dose of independent journalism.

Alberta can issue grid alerts when electricity demand threatens to outstrip supply — i.e. there’s risk of a blackout. This can happen for a number of reasons. 

A warming planet, with warmer summer months, can have you reaching for the AC remote. Our phones need charging and fridges need to stay plugged in. Add to the grid the data centres Alberta wants to build so we can ask our AI agent of choice to respond to our emails. The list goes on and on. 

And as much as the province would like to say it’s because of renewable energy projects, the data tells a different story. Prairies reporter Drew Anderson breaks it down in our latest video.

Want to make sure you don’t miss our latest work? Subscribe to our channel on YouTube and follow us on TikTok.

Thanks for watching!

The Narwhal’s reporters are telling environment stories you won’t read about anywhere else. Stay in the loop by signing up for our free weekly dose of independent journalism.

A major Canadian oil and gas company reported dozens of incidents at its pipelines after the provincial regulator exempted thousands of its pipelines from normal clean-up timelines. 

According to provincial data reviewed by the Investigative Journalism Foundation and The Narwhal, Canadian Natural Resources Ltd., or CNRL, reported 45 incidents since 2020, many of them spills of unspecified amounts of natural gas and other toxic cargo caused by metal corrosion at aging pipelines. 

Those spills came after a 2020 decision from the BC Energy Regulator to exempt roughly 4,300 of the company’s pipelines from the usual requirement that inactive pipelines be fully decommissioned within 18 months. Decommissioning, or deactivating, a pipeline includes removing any fluid and disconnecting it from the system. The sealed-off pipeline will remain in the ground in perpetuity. 

A CNRL spokesperson did not directly respond to a question about whether the spills occurred at pipelines associated with the exemption. Neither did the BC Energy Regulator.

Most of the pipelines operated by CNRL are short, transporting fracked natural gas and other fuels from wells scattered across northeastern B.C. to larger pipelines which carry the products to consumers or exporters. But even after those wells have run dry, the pipelines associated with them can still leak leftover contaminants into the local environment.  

“If it’s not properly [decommissioned] after its end of life, you have a substantial risk of groundwater contamination,” Philip Gass, a director of the energy program at the Ottawa-based International Institute for Sustainable Development, said in an interview. 

Gass said such spills might go unnoticed.

“If it’s been sitting there for a long time, you have to be really careful about the monitoring because this isn’t an active pipeline where you would notice a spill right away,” Gass said.The BC Energy Regulator reports for the CNRL incidents include leaks of natural gas, liquid hydrocarbons and produced water — a byproduct of oil and gas extraction that often contains heavy metals and hydrocarbons. Of the 45 reported instances, 23 were due to metal loss, often internal corrosion that allowed toxic fluids to escape.The regulator said incidents don’t automatically mean spills, since they can also include “incidents with the potential to affect pipeline integrity.” But many of the CNRL incident reports explicitly indicate that they resulted in spills or pipeline failure.

The regulator did not say how much of each fluid leaked into the surrounding environment or if there was any ecological damage associated with those spills.

Critics argue the spills are further evidence the regulator erred in giving CNRL such a broad exemption, which they called a sign of the undue influence the oil and gas industry has on provincial regulators. 

“It doesn’t give us a lot of faith that the regulatory system is operating as it should,” BC Green Party MLA Jeremy Valeriote said. 

‘No impact to the environment’: CNRL

For comparison, in the six years prior to 2020, CNRL reported 25 incidents at its pipelines, 17 of which were due to metal loss. 

A CNRL spokesperson said the company operates 14,896 kilometres of pipelines in B.C. and that spills are dealt with properly and promptly. 

“Clean-up and remediation activities were completed, resulting in no impact to the environment,” the spokesperson said of the 45 incidents since 2020. “When events occur, such as equipment malfunction that results in an incident, we have safety and environmental management systems in place to quickly manage these events. To mitigate any impacts, incidents are quickly and effectively managed in accordance with our structured emergency management and spill preparedness programs.”

Daryl Foley, president of Group 10 Engineering, said producers like CNRL work hard to minimize incidents.

“Their intention is to do the right thing and to prevent spills because it costs them an enormous amount of money when they have a substantial spill,” he said in an interview. Foley’s Calgary-based company works with companies and producers on pipeline integrity issues and advises the Alberta and B.C. regulators on best practices. “I’m not claiming that everybody’s perfect — if perhaps they’re ignoring it and there is a residual risk of environmental impact, well, they need to pull up their socks and get after it and prioritize based on where the highest risks are.”

Foley said corrosion affecting pipelines has been an issue for decades, but fracking can exacerbate the problem.

“The challenges are real,” he said. “Northeast B.C. in particular, they’re fracking these wells to try to enhance production. The challenge is after fracking, they’ve run into issues where they can get some of these frac solids, and some of them can be really aggressive sulphur compounds.”

Frac solids are a mixture of silica sand, water and chemicals used in fracking to extract oil or gas trapped in underground rock formations. Those mixtures, if not properly removed from sections of pipeline that move material from wells to larger, safer transportation pipelines, can damage the metal and cause leaks or spills. Foley said any pipelines with potential or identified corrosion issues associated with active wells should be prioritized.

“Are these wells known to have been discontinued properly?” he wondered. “That’s really what they should be checking in on and making sure of. Any that hasn’t been discontinued properly, that needs to be dealt with immediately.”

CNRL pipelines exempt from clean-up timelines

The BC Energy Regulator said a 2020 audit identified thousands of CNRL pipelines that were either inactive or soon would be. The regulator said that’s what prompted it to strike a deal with the company, one of the largest oil and gas producers in the country.Under that deal — which was not publicly disclosed at the time — the regulator agreed to exempt thousands of CNRL pipelines from normal clean-up timelines in exchange for the company committing to deactivate all of them by 2028, with targets to meet every year until then. 

The regulator later found in 2023 that the company was not meeting those commitments, but reinstated the deal without penalizing CNRL.

A regulator spokesperson said the deal was “the most effective way to bring CNRL into compliance” and claimed the agreement “was not a removal of oversight.” 

As of this month, the regulator said only 474 pipelines remain to be deactivated out of an original total of 4,312.

“As such, CNRL continues to meet and exceed the required deactivation targets set out in the conditions of the exemption,” the spokesperson said.

Drew Yewchuk, an environmental lawyer and PhD student at the University of British Columbia, said it’s not clear what the regulator or the public gained from the deal with CNRL. 

“The regulator is getting less than what the legal requirements are, and the company only has to do less than what was the legal requirement. So what is the regulator getting from these deals?” Yewchuk said.

He said oil companies often argue meeting regulatory requirements would endanger their operations, putting pressure on politicians to intervene.

“They don’t want to cause job losses, and that’s the threat that companies always have in the background,” Yewchuk said. “They say, ‘Look, if you force us to invest too much here, we’re going to move out of this jurisdiction.’ ” 

But he said CNRL isn’t a struggling company. The Calgary-based company reported net earnings of $10.8 billion in 2025.

“CNRL is not out of money,” Yewchuk said. 

Regulator ‘way too tied to industry’

Gass said oil and gas remediation can become a public responsibility if the operating company goes bankrupt. Some provinces, including B.C. and Alberta, charge oil and gas companies an annual levy to clean and shut down so-called “orphan wells” left by defunct firms.

But if the company is still active and profitable, the regulator’s role should be to enforce the rules, Gass said.

“In an ideal situation you have a regulatory regime that assures the accountability and has the enforceability to level penalties for actors that don’t do the remediation as needed,” Gass said. 

The BC Energy Regulator, like other regulators in Canada, is funded by an annual levy charged to oil and gas companies.

While proponents argue an industry-funded regulator is sustainable, critics like the Green Party’s Valeriote argue it creates a dependence that gives energy companies undue leverage in negotiations.

Valeriote said granting exemptions like the one given to CNRL is unfair to other companies following the rules and is “erosive to the regulator’s reputation.”

“I think there’s probably a cultural and systemic issue there and that they’re way too tied to the industry,” Valeriote said. 

The Narwhal’s reporters are telling environment stories you won’t read about anywhere else. Stay in the loop by signing up for our free weekly dose of independent journalism.

The price tag to clean up orphan oil and gas wells in Alberta increased by nearly 50 per cent since last year, bringing the estimated total to $1.66 billion, according to the latest annual report from the Orphan Well Association.

The report, released last month, attributes the increase to an “influx” of orphan wells from a company called Long Run Exploration Ltd. The price tag to clean up the thousands of orphan sites left behind by the company is estimated by the association to be $500 million.

“A surge in inventory is not new for the [Orphan Well Association]. … These struggling companies are on our radar for a long time,” the annual report reads. 

“We know the assets will eventually come our way, and plan in advance with the [Alberta Energy Regulator] to ensure we are ready to tackle the challenge.”

Alberta’s Orphan Well Association is a not-for-profit organization launched in 2002 that acts as a backstop when delinquent oil and gas companies leave behind inactive wells that need to be cleaned up. It was designed to be funded by industry in the form of an annual levy, but has received government grants in the past and gets an annual interest-free loan from taxpayers. 

In response to questions from The Narwhal, Lars De Pauw, the president of the Orphan Well Association, said by email, “The pace of closure will depend on future orphan levies which have not yet been determined.”

All companies pay into an orphan well fund, to make a pool of money available for when companies go bankrupt, or otherwise walk away from their liabilities. Last year, the orphan well levy added up to $144.45 million. This year, after a seven per cent increase set by the Alberta Energy Regulator, it increased to $154.6 million.

Last year, the association safely sealed 721 wells, according to the annual report, and received reclamation certificates for another 850. The report says this is the equivalent of “over 15 square kilometres of land returned to Albertans, an area equivalent to 2,100 [Canadian Football League] football fields (including end zones!).”

That’s not enough to make up for the decades-long backlog of orphan wells, according to public interest lawyer Drew Yewchuk.

“The bottom line is that Alberta’s orphan problem continues to grow,” Yewchuk wrote in a University of Calgary Public Interest Law Clinic blog post about the latest annual report. “All signs point to an orphan well problem that will become too big to solve so that a large share of the costs will be socialized, with taxpayers left to pay the bill for closure work.”

Yewchuk cautions the amount taxpayers could be on the hook remains to be seen. “This is not an all or nothing question of whether costs are passed to the public. Both the federal and provincial governments have already paid some costs for the closure of oil sites, but the amounts are small compared to the total cost,” he told The Narwhal by email. “The thing to watch is how much of the cost gets passed to the public.” 

Alberta’s orphan well problem grows year after year

According to the Government of Alberta, there are an estimated 466,000 oil and gas wells in the province. More than half of those are no longer producing, some of which have been properly plugged, while others are in a state of temporary suspension. And some are orphans: a well that no longer has a legal or financial owner. 

The most common cause is an insolvent or bankrupt oil and gas company that has left behind a long list of wells that were never properly decommissioned or cleaned up. Those wells, pipelines or other related facilities then become “orphans.” 

But they still need to be properly plugged and reclaimed, according to provincial rules. That falls to the Orphan Well Association.

The association’s inventory currently lists 7,382 wells that need to be decommissioned — as in, safely sealed — and 9,148 sites that need to be reclaimed, which means restored to what’s known as “equivalent land capability” to get back to the ecological, agricultural or other pre-drilling state of the land.

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

For comparison, in 2013, the Orphan Well Association had just 387 orphans in its inventory of sites that needed to be reclaimed.

The total price tag to clean up wells the association is responsible for has also increased. According to Yewchuk’s analysis, “the total amount owed has increased for five of the last six years and has more than doubled from 2021 to July 2026.”

Thousand of wells were orphaned in April

The thousands of new wells from Long Run Exploration Ltd. that landed on the Orphan Well Association’s books this spring ended up as orphans after a 2024 deal with a Chinese company fell through. That deal would have seen all of Long Run’s shares purchased for $22 million.

In April, the Alberta Energy Regulator announced the company’s wells were officially orphans. That meant 4,031 wells, 383 facilities and 2,121 pipeline segments previously owned by Long Run Exploration Ltd. were transferred to the Orphan Well Association. 

The association reported updated numbers after verifying the status of each site: 2,980 wells and associated facilities and pipelines need to be decommissioned and 938 sites have already been sealed.

The association’s annual report is optimistic the sites do not pose any extraordinary risks.

“Given the nature of the Long Run assets, we do not foresee any of the sites posing a high risk to public safety or the environment,” it said in its annual report.

De Pauw, the president of the Orphan Well Association, said by email, “We have incorporated the Long Run wells into our overall program. We don’t see them any differently as other orphan assets and will continue to prioritize sites based on risk and those on private land while ensuring efficient operations. ” 

Cleaning up one orphan well involved demolishing homes

According to the association, the average cost to safely seal each well is $28,800 and the average cost to reclaim the site is $27,000, though actual costs can vary widely depending on the complexity of the cleanup. 

In its annual report, the association cites an example in Bonnyville, Alta., where a 1950s-era orphan well was found to be leaking methane into a home. Two houses and a duplex were purchased and demolished, and the well was safely sealed — a complicated and expensive endeavour. “The homeowners were disappointed, of course,” Cliff Pybus, land and stakeholder coordinator at the Orphan Well Association, said in the annual report. “But also relieved that the [association] was taking charge and fixing the situation.”

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

“In recent years, levy revenues have not been enough to keep pace with the increasing number of orphan sites being transferred to the [Orphan Well Association],” the auditor general wrote in 2023. Back then, the total price tag of cleaning up orphan wells was a little more than half what it is today.

The Narwhal’s reporters are telling environment stories you won’t read about anywhere else. Stay in the loop by signing up for our free weekly dose of independent journalism.

Canada’s large oil companies are raking in record profits during an energy crisis.

We’ve been here before — but unlike last time, Ottawa isn’t prodding the industry to use more of the money to clean up its act. In some ways, it’s even volunteering to pick up the tab.

The last time was just four years ago, when Russia’s invasion of Ukraine led to Western sanctions on Russian oil and fears about global energy supply. The price of oil shot skyward, and large Canadian oil companies reaped the benefits, taking in billions of dollars in windfall profits.

The oil and gas industry is the largest source of Canada’s greenhouse gas emissions, which cause climate change that scientists say has been driving major heat waves and wildfires across the country this summer, destroying communities and upending lives.

Yet instead of using its windfall during the Russian invasion to invest heavily in non-emitting energy sources, or to widely deploy technology to decarbonize its operations, the industry began funnelling a larger proportion of its revenues to shareholders, while a group of oilsands companies went to governments asking them to cover much of the cost of their proposed emissions projects.

The federal environment and climate change minister at the time, Steven Guilbeault, pushed back, suggesting oil companies needed to put their money where their mouth is when it came to their own publicly stated environmental goals.

“As Canadians see those profits, we need to see reinvestment into cleaner energy instead of share buybacks,” Guilbeault said in a video posted online in October 2022.

Share buybacks are when companies use cash to buy their own shares back from investors. It’s a different way of giving money to them than dividends, which distribute earnings to shareholders.

The Iran war, that began this February, is again leading to big profits for Canada’s oil industry, which are again being directed in part to shareholders.

The conversation has reignited calls for a windfall profits tax on the oil and gas industry, something more than 60 unions and civil society organizations have been calling for.

In a survey this May by Liaison Strategies, 66 per cent of a random sample of 1,526 Canadians reached by landline and cell phone also supported a tax on oil and gas excess profits, with the revenues going to help lower energy bills.

Elbows Up For Climate, which represents almost 300 mayors, councillors and local officials from across Canada advocating for national environmental projects, is one of the groups calling for a windfall tax.

Former Toronto mayor David Miller is the co-chair of Elbows Up For Climate alongside former Montreal mayor Valérie Plante. Miller told The Narwhal such a tax makes sense given the global fossil fuel industry spent decades obscuring the truth about climate change and lobbying governments to roll back climate action, and so is “in many ways responsible” for delaying the economy’s transition to clean energy.

“We are in a frightening summer from wildfire smoke. The damage yet again will be in the billions, and the question is, who should pay for that? Should it be the general public?” Miller, now managing director of a global network of mayors called the C40 Centre, said. “Or should it be the people, the entities, that are causing the problem?”

“The entities that are causing the problem — which is climate change, that’s what’s making the wildfires so bad — are the fossil fuel companies, and they should pay for the damage. It’s a user-pay kind of principle, and because of the profits they’re making as a result of the U.S.-Israel attack on Iran, it’s a very appropriate moment.”

Oil companies argue they already pay significant taxes as well as royalties, which are separate payments that companies make to the province that owns the resources. In 2024-25, Alberta took in $17.2 billion in royalties from the oilsands.

But the Vancouver-based Centre for Future Work has argued that royalties collect “only a small fraction” of the increased revenues from higher oil prices. In 2022, they found, oil and gas profits jumped almost three times as much as the increase in royalties.

Applying a new windfall tax on oil profits today could generate between $18 billion and $46 billion over the next year, depending on the tax rate and how much of a company’s profits it applies to, according to the Canadian Centre for Policy Alternatives.

The Narwhal asked Environment and Climate Change Minister Julie Dabrusin’s office whether she believes, like Guilbeault did, that oil companies should be spending more on emissions reductions, and what she thought of a windfall profits tax.

“Oil and gas companies have an important role to play in driving down Canada’s emissions,” Dabrusin’s director of communications Chris Zhou responded in an emailed statement.

Zhou said the government was focused on “durable, unifying solutions that will deliver sustained emissions reductions over the long term,” including restrictions on methane, a greenhouse gas, in the oil and gas sector, as well as the industrial carbon pricing system.

Oil companies bringing in record-breaking profits amidst Iran war

The Iran war has led to the intermittent closure of the Strait of Hormuz, the chokepoint between the Persian Gulf and Arabian Sea that one-fifth of the world’s oil is shipped through.

It created the “largest supply disruption in history,” according to the International Energy Agency, and sent oil prices higher again. The higher price translated to big profits for the world’s largest oil companies, and those in Canada have been no exception.

Earlier this month, Canadian Natural Resources Limited, one of the country’s largest oil and gas companies, reported $4.5 billion in profit in the second quarter, which covers April to June. That result was “the strongest in the history of the company,” Chief Financial Officer Victor Clinton Darel said.

The company returned $2.4 billion to shareholders in the form of dividends and share repurchases. This year, he added, was the 26th consecutive year of dividend increases.

The record results followed a report from Cenovus, one of Canada’s large oilsands companies, of a $2.9-billion profit in the second quarter, its “best quarterly financial result ever,” president and CEO Jon McKenzie said. Cenovus plans to increase shareholder returns, and sent $1.4 billion to them in the second quarter.

“We would never apologize nor take credit for a higher commodity price environment, but the key is to run well while it lasts and capitalize on the opportunity,” McKenzie said.

A third oilsands firm, Suncor, recently posted a $3.7-billion profit, and returned $1.7 billion to shareholders — it too said it plans to spend more money giving cash to investors in return for their shares.

Imperial Oil, a Canadian firm majority-owned by one of the world’s largest oil companies, ExxonMobil, posted a quarterly profit of $2.2 billion. John Whelan, the chairman, president and CEO, said Imperial has grown its annual dividend for 31 years.

In addition to reaping rewards from the higher price of oil, Canadian companies have also been creating more of it. Oil production hit a new record last year in Canada, and crude oil production hit the highest volume this May since comparable records began in 2016, according to Statistics Canada.

This year, Cenovus expects to join the club of companies worldwide that can produce, on their own, the equivalent of a million barrels of oil per day, on average. Only one other Canadian company can do that, Canadian Natural, which also said it had hit a new quarterly production record.

Oil execs praise Alberta deal that taxpayers could be on the hook for

During their earnings calls this summer, executives praised Prime Minister Mark Carney’s deal with Alberta Premier Danielle Smith — in which the federal government has hinted it’s prepared to spend significant public dollars.

Canadian Natural, Cenovus, Suncor and Imperial Oil are four of the five members of the Oil Sands Alliance, formerly known as the Pathways Alliance, which signed a trilateral memorandum of understanding with the federal and Alberta governments that envisions a new oil pipeline to the West Coast, to be filled with increased levels of oil production, as well as a new emissions reduction project in the oilsands called Pathways, which will rely in part on carbon capture technology.

Ottawa says two government-owned corporations will own most of the oil pipeline and one of them will develop and run it. The only private-sector involvement announced so far is a pipeline company signing a non-binding agreement to take a 10 per cent interest during construction, with possibly another 10 per cent interest when the pipeline begins operating.

Pressed by CBC News to reveal how much federal money would be involved in building the new pipeline, Natural Resources Minister Tim Hodgson said that while he didn’t have “the numbers in front of me right now,” the cost to build an earlier oil pipeline — the Trans Mountain expansion project, which cost between $30 and $40 billion — was a “reasonable thing to look at.”

The government’s deal with Alberta also includes a commitment from Ottawa to “offer financing or support mechanisms” supporting the operating costs of carbon capture and storage projects.

It’s hard to precisely tally up how much this financing and support might cost Canadians, but the government has already committed billions of dollars in the form of carbon capture tax credits, funding for carbon contracts and other related research and development efforts.

At the same time, it’s unclear how much of their own money oil companies are willing to spend on the industry’s infrastructure — whether that’s to move more oil, or to lower their emissions.

Companies tight-lipped about environmental progress, vocal on environmental regulations

Many major oil companies have cited Trudeau-era changes to the federal Competition Act as a reason why they cannot publish information on their environmental performance on their website or in corporate disclosure reports.

The changes introduced an anti-greenwashing requirement for businesses, ensuring they backed up claims about protecting the environment or tackling climate change with evidence. (While the Carney government removed a rule that required this evidence to conform to internationally recognized standards, it left the broader requirement in place.)

Suncor’s 2025 report on sustainability says the company aims to “reduce the greenhouse gas emissions intensity of our base business,” but notes the report intentionally does not contain any “environmental content or data” due to the law. Cenovus says it does not publish any information on its website regarding its environmental performance or targets, for the same reason.

Imperial Oil’s website says it does not publish “an active representation” of its environmental performance although it mentions efforts in “lower-emission fuels,” renewable diesel, lithium and carbon capture technology. Canadian Natural’s website points to reclamation projects, like tree planting, at its oilsands sites.

The four companies, as well as the Oil Sands Alliance, did not respond to requests from The Narwhal for how much money they have spent over the last year on emissions reductions projects, or their opinion of a windfall profits tax.

They have been outspoken, however, about how environmental policy is affecting their bottom lines.

​McKenzie, at Cenovus, said in June that a new oil pipeline to the West Coast could not be ⁠financed by the ​private sector because of Canada’s industrial carbon pricing system. “Industry has been clear that the industrial carbon tax is insidious and it should be revoked,” he said.

On the July earnings call, ​after announcing record profits, McKenzie again described the industrial carbon pricing system as an “uncompetitive carbon tax that uniquely burdens Canadian industry.”

But he praised the Canada-Alberta deal, saying it “creates a framework for governments and industry to work together on production growth, emissions reduction and expanded market access.”

Similarly, Scott Stauth, president of Canadian Natural, said the agreement was a “positive first step” and said it would “benefit all of Canada by providing more jobs, combined with social and economic benefits to our country.”

“It’s a very different mood and tenure today than it has been in the past. We’re encouraged by that,” Suncor president and CEO Rich Kruger said about the Alberta deal, although he also said there was still “a lot of work to do.”

Oil Sands Alliance President Kendall Dilling said in a statement posted July 13 that the trilateral deal was a “framework that is positive for the oilsands industry and provides a step forward to help enable production growth and to advance the Pathways project.”

“It helps meet our shared vision to grow Canadian oil production and benefit Canadians across the country,” he said.

Windfall profits tax could help offset affordability crisis, advocates say

For his part, Carney posted a video online in June suggesting the world needed more of Canada’s fossil fuels, as a result of the Iran War.

“The hard truth is that we don’t control the price of oil, so what we’re doing is helping Canadians through tough times in the short term,” the prime minister explained.

The government suspended the federal gas tax for the summer as an affordability measure, Carney said. But he also argued that addressing global “energy security” means ensuring Canada supplies the world with as much oil and gas “as possible.”

While he acknowledged this “will mean that our emissions will be higher in the next few years than they were projected to be under the previous government’s plan,” he said Canada “can’t afford to restrain the growth of an important part of our energy mix, oil and gas, to meet a short term goal.”

Carney also claimed Canada’s oil would be “produced responsibly and with a clear focus on lowering emissions over time.”

For Elbows Up For Climate, though, the fact remains that carbon pollution from fossil fuels is directly and indirectly the cause of tens of billions of dollars in damages from climate-driven extreme weather, Miller said.

Annual insured losses reached $37 billion between 2016 and 2025, according to the Insurance Bureau of Canada.

“It’s quite remarkable and eye-opening when you look at [insurance] statistics, and those are happening because of the exploitation of fossil fuels,” Miller said.

“Expanding oil and gas production puts more Canadians at risk of extreme weather, extreme heat and other climate-related disasters. We actually can’t afford those disasters.”

Several groups like the Green Budget Coalition, Canadians for Tax Fairness, Seniors For Climate Action Now, For Our Kids and 350.org have also submitted budgetary recommendations to the House of Commons finance committee that endorse a windfall profits tax on oil and gas companies.

Thomas Green, senior manager of climate solutions at the David Suzuki Foundation, part of the Green Budget Coalition, pointed out that the United Kingdom has its own windfall tax.

Between 2022 and 2025, the UK’s Energy Profits Levy raised 9.1 billion pound sterling, or $17 billion at today’s exchange rate.

The coalition wants to see a new levy on oil and gas companies linked to when oil prices exceed certain thresholds — indexed to inflation and periodically reviewed — and for the money to be allocated toward affordability and climate action measures.

“These profits come at the expense of affordability for everyday Canadians,” Green told The Narwhal.

“A windfall profits tax would at least rectify some of the injustice that we see right now.”

The Narwhal’s reporters are telling environment stories you won’t read about anywhere else. Stay in the loop by signing up for our free weekly dose of independent journalism.

Assar Grinde is the kind of man whose calm is infectious, even as he rattles off an encyclopedic knowledge of facts about drought, water and the impacts of fracking on the region he calls home. A cattle rancher by trade who studied geology at the University of Alberta, you get the sense he’d rather be tending his herd than fighting with regulators and oil and gas companies.

But on a Sunday in early July after a morning on the ranch, he sits in the back of his friend Daniel Iseli-Otto’s truck, sporting a sweater knit by Iseli-Otto’s mom, and talks about the reasons he can’t just walk away.

It started three years ago when Lloyd Creek — a tributary of the Blindman River, which runs through the land Grinde’s family has ranched for generations — dried up. It was something he’d never seen before and he says the oil and gas companies were still pulling water from the river.

“We wanted to make sure that the river didn’t dry up because we thought that was crazy,” Grinde says.

He and Iseli-Otto helped found the Blindman River Watershed Society and dove into the labyrinth of data used by the Alberta Energy Regulator and the equally bewildering bureaucratic divisions of the provincial government.

It’s a funny time to be talking about the stress on the Blindman River watershed and the concerns he and Iseli-Otto have when it comes to the vast quantities of fresh water being used by oil and gas companies for hydraulic fracturing, or fracking.

The fields around Rimbey, Alta., about 200 kilometres north of Calgary, are saturated in surreal hues of green, stark against the grey skies of an abnormally wet July that has brought much-needed rain.

It’s a far cry from the drought-like conditions of May and June, conditions that have become all too common in a region suffering through a decade-long dry spell.

But the sudden rush of water isn’t enough to quell the concerns of area ranchers and residents who watched that creek run dry and their drinking wells drop. They say the rain isn’t enough to make up for how much has been lost from the aquifers — the deep underground natural reservoirs that feed those wells.

And then there’s the issue of oil and gas companies using billions of litres of water to crack open the earth beneath those green fields and exploit one of the hottest gas fields going, the Duvernay. They take surface water when there isn’t any to spare, and a fleeting moment of plenty might only make it worse, according to landowners who met with The Narwhal.

Grinde says promises were made by those companies, but rarely kept.

“ ‘We’re going to be taking the water at high flows when there’s too much of it, and we’ll store it and then use it when we need it.’ That was the industry’s sales pitch,” he says, driving through the region southwest of Edmonton along with Iseli-Otto. “But then we’ve been in a drought eight of the last 10 years, and they are still pulling water down.”

Dana Kreil, the chair of the nearby Medicine River Watershed Society, and a councillor for Lacombe County, says there’s no trust in the province to monitor the water and to intervene. Her society has bought its own monitoring equipment and is pressuring the government for solutions.

“You can’t fool the locals,” she says, making it clear she’s speaking for the watershed society and not the county. “There are people telling me the top of their runners wouldn’t get wet in that river. So you can’t tell me that those are acceptable levels for pumping from there.”

‘You only get conflict when there’s scarcity’

The Blindman River, as well as the Medicine, aren’t among the great waterways of the world. With enough momentum, it wouldn’t be hard to leap from one bank to the other. They are slow and meandering, but they are critical to ranchers and farmers.

They are also tenuous.

Neither river is fed by the mountain glaciers to the west. They rely instead on spring runoff and underground aquifers to keep water flowing. This year’s early-summer drenching is an indication of the feast and famine cycles expected to be the norm as the climate shifts — droughts with sudden onslaughts of rain. Grinde says his ranch received almost as much rain in June as it did the entire year previous.

For decades, fracking companies here have been injecting water deep into the ground to break up rock holding gaseous wealth in tight crevasses. That water, vast quantities of it, is almost entirely permanently lost to the water cycle as it remains trapped in the reservoirs that previously held gas. The practice was largely accepted by area landowners, but then water became scarce and drilling activity increased.

“We haven’t had to care about fresh water because we never had this issue before,” Grinde says. “You only get conflict when there’s scarcity, and you have that imbalance between supply and demand, and that’s really what’s happened in the last few years.”

Once Grinde and others started paying attention, they discovered a system of what they say is weak oversight, weak data and regulatory capitulation.

Water use is overseen by both Alberta’s Environment Ministry and the energy regulator — depending on who’s using the resource — and Grinde says it leads to a lot of plausible deniability. Water monitoring in the area is based on a federal government sensor 50 kilometres away in Blackfalds, Alta., but Grinde says it doesn’t actually measure the flow of the river, just the water pressure. Even if it did, Grinde thinks the minimum flows established by the province to determine when a company can pull river water for fracking are too low.

The Alberta Energy Regulator did not answer a question about the monitoring situation on Blindman River, but said monitoring is used to inform when a company can divert water. It noted that monitoring can be seen on the Alberta Rivers site.

The regulator says companies are responsible for measuring flow if there is no station nearby.

“So then that kind of led us down this path of trying to figure out: ‘Do you guys have rules around it?’ ” asked Grinde.

For some in the area, the answer is more uncertain than they’re comfortable with.

Company wants to pull billions of litres from critical freshwater aquifer

In March, Spartan Delta, a fracking company operating in the area, applied for a water licence to pump a maximum of 475 million litres of water per year — about 2.4 million bathtubs’ worth — from the Paskapoo Formation, a vast underground freshwater reservoir that stretches south past Calgary and north past the Athabasca River near Fox Creek.

That raised red flags for those in the region already worried about a strained system.

Grinde wants the government to prevent oil and gas companies from accessing shallow fresh groundwater for fracking, implementing a ban now so that it doesn’t have to draft new rules in the midst of a full-blown crisis.

“Right now [the companies] say, ‘Well, we don’t have any more surface water available to get licensed, we’re just going to start drilling shallow groundwater wells,’ which is really concerning because we don’t know enough about the groundwater, and it’s so vital to everybody who’s living here,” he says.

Tens of thousands of wells tap into the aquifer for drinking water, as do towns across Alberta. According to a report by the federal government, the Paskapoo “supports more groundwater wells than any other aquifer system in the Canadian Prairies,” making it “the most significant supply of groundwater” in the whole region.

That same federal report — published almost 20 years ago — also cautioned the aquifer is slow to recharge and the amount of water that can be pulled from the aquifer might be limited and may have already been exceeded in 2008.

Spartan Delta already pumps water from the Medicine River, with hoses stretching along ditches and culverts throughout the region pulling water into massive reservoirs. It also uses recycled water from its operations, but that only accounts for approximately 10 per cent of its use.

In 2024, the latest year of data from the Alberta Energy Regulator, Spartan Delta used approximately 171 million litres of fresh water for fracking. Its latest application shows the company estimates it will need much more than this, around 1.5 billion litres per year for the next 10 years.

The company did not answer emailed questions but sent a statement instead, saying it is focused on “responsible, sustainable development of oil and gas.”

Spartan Delta said it adheres to all rules and regulations set out by the regulator, Alberta’s Environment Ministry and local bylaws.

“All of our water use is determined by Alberta Environment,” reads a portion of its statement. “The company receives temporary diversion approvals, term licences and has undergone several audits to validate we are in compliance with all of the terms of the water approvals. All resident concerns are evaluated by the appropriate regulating body of our activities during the approval process.”

The regulator also did not directly answer questions emailed by The Narwhal, but did provide information on water use. An unidentified spokesperson said the regulator reviews all water licence applications and considers risks to individuals and the environment. The spokesperson added there are restrictions on water use if levels drop below prescribed thresholds and that restrictions can also be implemented in response to “landowner concerns.”

Analysis on aquifers is conducted by hydrogeology experts, the email said.

Though landowners are concerned about Spartan Delta’s water use, the company is a small player compared to others.

Parallax Energy Operations used almost one billion litres in 2024, while Canadian Natural Resources Ltd., one of the largest oil and gas companies in Canada, used 2.9 billion litres of fresh water for operations across the province. Overall, fracking consumed 20 billion litres of fresh water in 2024, up sharply from the seven billion litres consumed in 2013.

Grinde’s goal is to prove to the province and the regulator that the aquifer is dropping, realizing that officials could just turn around and say, well, it’s a drought.

“But even if it is a drought, the volume of water that the companies are using for fracking is accelerating that,” he says. “It could be that if there’s only a certain amount of water, you have to justify the use for certain things, right? So maybe you have to talk about hierarchy of use.”

Time and again, Grinde, Kreil and Iseli-Otto talk about the amount of work required to collect information, to get in touch with provincial officials, to make someone listen. Without decades of data, the response from officials and companies is: prove it.

“It’s the province’s job,” Kreil says. “It’s not the watershed society’s job. We’re volunteers.”

The provincial government did not respond to questions emailed by The Narwhal.

Alberta ranchers say their bison herd collapsed when a fracking company moved in

It’s easy to look out across the fields and patches of trees and imagine the landscape in central Alberta is largely unchanged, but Iseli-Otto, who works as a carpenter and has lived here his whole life, looks out his truck window and remembers bush where fields now stretch — a child’s wilderness transformed into cropland. It’s a reminder of how quickly things can change. How the immutable becomes a memory.

The change can be slow, or it can come on in a relative blink.

Tucked into a secluded corner of the countryside, is the home of Butch and Nicole Smith, two bison ranchers who have lived and worked in the area for decades, with the dream — shared by one of their daughters — of passing their ranch to the next generation.

Inside the home, a stuffed cougar looks down from its final perch above the kitchen, and the walls are covered in framed rodeo photos showing the victories of the family’s horses. Tail Light was the “team roping heading horse of the year.” Hickory, the “2011 pole bending horse of the year.” Their daughters have won an astonishing number of championship rodeo belts and saddles, all of which are on display.

A hint of the Smiths’ directness, and their frustration, comes in the form of a small sign by the kitchen table: “What (and I can’t stress this enough) the f*ck,” it reads.

Over bison burgers and sausages, the Smiths talk about how Spartan Delta cleared the land across from their feedlot and built two massive reservoirs two years ago to store the vast quantities of water the company pumps. They talk about how construction and pumping for the reservoirs, which bisect a wetland, led to startling changes in their bison herd.

“We started seeing the wildest behaviour from them,” Nicole says. “They’re very habitual animals.”

The herd was refusing to move to the areas they usually feed, and there was a sudden drop in their herd.

Nicole says they had 240 pregnant cows in the fall of 2024, but only 194 live births.

“We had many dead calves, aborted calves and calves that starved as stressed mothers produce not enough milk,” she says.

The Smiths blame the stress of the industrial activity and the disruption to stubborn routines.

The Smiths, however, aren’t the types to sit back and watch. They say they’ve spoken with their MLA, Jason Nixon, with the premier, with two environment ministers — Rebecca Schulz and RJ Sigurdson — and Energy Minister Brian Jean. They are working with Ecojustice, an environmental legal outfit, and were invited by the Alberta NDP to sit in the legislature last spring after speaking with MLA Nagwan Al-Guneid.

Now, after two years of fighting, they’re losing faith and plan to move.

“Neither one of us is a — how do I say it — a sitter arounder. I’m not gonna sit here and be miserable. I can’t even walk anymore because both ways just reminds you of all of it,” Nicole says.

“I’m raging when I hit the end of my driveway — every single time.”

‘There’s very little oversight right now’

Tensions are high in the region where fracking butts up against homes and ranches. In early July, a rumour spread that some of the hoses that pump water from ponds and rivers were shot at, but the Alberta RCMP said there were no reports of an incident on that day. Perhaps most telling was that none of the people who spoke with The Narwhal seemed surprised, although no one supported the idea and warned of the danger of puncturing the high-pressure lines.

There is a real sense that landowners have been abandoned in favour of oil and gas.

Kreil, whose society includes representatives from eight municipalities, including Red Deer, Lacombe County and Sylvan Lake, said the group recently met with the minister of Environment and Protected Areas and the CEO of the Alberta Energy Regulator to talk about the stress on the watershed. In its presentation, the society noted more than half of all fresh water in their watershed is allocated for oil and gas. Temporary water licences are almost entirely for fracking.

She says the minister told them to write a resolution calling for policy changes through the Rural Municipalities of Alberta — an organization which represents towns and districts across the province.

“I think he felt that he had dealt with us enough to say: ‘Write a resolution,’ ” she says.

Kreil stresses she’s not opposed to oil and gas, or to fracking in particular, but there has to be a balance.

“When we went to the minister, we said we want some solutions,” she says. “We’re not just coming here to bellyache and complain.”

Her organization wants to see more wastewater treated and reused, including municipal wastewater, to reduce or eliminate fresh water use. It wants better data on the state of the watersheds and a better understanding of drought and its impacts. And it wants new regulations governing use by agriculture, oil and gas and municipalities.

But those critical of the way fracking companies are operating all point their finger at the regulator when asked what the biggest problem is. The rules are weak and out of touch, responsibility is passed on and there’s no enforcement, they say.

“The problem with the Alberta Energy Regulator is there’s very little oversight right now,” Kreil says.

Iseli-Otto says he tried alerting a contact at the regulator about companies pumping from the Blindman River in May when the water levels were worryingly low, but nothing came of it.

Two days later, he was driving home and the pumps were running.

“So I texted him and I said, ‘Hey man, pumps are running, what’s going on? Why is this happening?,’ ” he says. In screenshots of the text messages shared with The Narwhal, Iseli-Otto then asks if someone from the regulator had checked to see if the pumps had stopped.

“That’s the point at which I got the automated text message saying this number is not monitored.”

Alberta pushes to double production, build pipelines

The regulator is an arms-length government body, but that doesn’t mean it’s entirely independent. The government sets the overall policy direction for the regulator to follow, for example, and the government appoints the regulator’s board of directors.

Recently, it appointed David Yager to the board, a long-time friend of Premier Danielle Smith who also acts as one of her special advisors, and tasked him with overseeing a revamp of the organization.

There have also been revelations of direct intervention from the provincial government into regulatory decisions.

And the direction from the government is clear: it wants to double oil and gas production and it’s willing to incentivize companies to do so, even as it helps finance a new pipeline to the West Coast.

With the push for more production and without more stringent rules on water use, the problems in the area are likely to continue, or increase.

“We’ve had companies tell us ‘We’re not doing anything differently until the government tells us to,’ because it’s a competitive industry,” Grinde says.

“We said to the minister, as long as this is free, they will never change,” Kreil adds.

But in the end, something has to give, she says.

“You can’t be running the people out of water for oil.”

The Narwhal’s reporters are telling environment stories you won’t read about anywhere else. Stay in the loop by signing up for our free weekly dose of independent journalism.

This investigation is a collaboration between The Narwhal and Point Source, a U.K.-based investigative journalism organization.

LNG Canada told the BC Energy Regulator its Kitimat, B.C., gas export facility was likely to emit black smoke continuously for multiple days, a warning that came ahead of key environmental permits being granted, according to recently released documents.

The new documents, obtained by The Narwhal and U.K.-based investigative journalism organization Point Source through freedom of information legislation, raise questions over whether the regulator should have sought more assurances about measures to stop this kind of pollution before permits were granted.

Summary

• LNG Canada has been emitting more black smoke than originally planned and some Kitimat, B.C., residents are concerned.
• Black smoke can indicate gas is not burning efficiently, releasing higher levels of toxic pollutants, according to one expert.
• The BC Energy Regulator knew about the smoke ahead of giving the project approvals but has now ordered LNG Canada to make changes.

In July 2022, LNG Canada — a consortium of five foreign-owned companies led by Shell — submitted a document to the provincial government outlining its expectations around black smoke emissions.

“Given the unpredictable nature of these types of events, it is not possible to give a frequency of them occurring although an estimate is provided,” the consortium wrote. 

The colour of black smoke is caused by a concentration of particulates and unburned fuels, which is toxic. The estimate provided to the regulator said black smoke would be emitted at the facility for between 15 and 60 minutes one to three times per year prior to the facility completing 200 shipments. LNG Canada sent its 100th shipment in mid-June, nearly one year after its first. It also estimated slightly less dark smoke would be emitted continuously from the facility for between five and 15 days on four to six occasions in the first year

Despite this information, the regulator issued LNG Canada a facility permit requiring that black smoke not be continuously emitted for more than 15 minutes. The company committed to that limit, but has failed to keep to it.

On Jan. 6 2026, the export terminal emitted black smoke emissions during non-emergency conditions for more than seven hours. The next day, it emitted black smoke for over two hours. 

In April, the BC Energy Regulator told LNG Canada to identify the root cause of black smoke emissions during flaring at its facility in Kitimat, and implement a fix by October.

In late June, the regulator instituted new requirements, including mandated reporting of instances of black smoke emissions.

A spokesperson with the regulator said the facility’s permit “contains clear statutory requirements regarding black smoke emissions designed to minimize air pollutants to protect public safety and the environment.” 

“When our oversight activities identify non-compliances, such as in this case, we can place additional requirements (e.g., having to report black smoke) on permit holders,” the spokesperson noted in an emailed statement.

Black smoke from the flare stack of a LNG facility usually indicates that gas from the facility is not being burned off in an efficient manner and higher levels of toxic pollutants are being released, according to Tim Doty, a former oil and gas inspector with the Texas state government.

“The black smoke that can be visually seen being emitted from the flare is soot, basically,” Doty said in an interview. “In theory, flares are designed to burn in an efficient way that doesn’t produce this black smoke.”

According to the regulator’s reply to detailed questions, LNG Canada’s new requirements as of June include:

• Report to the BC Energy Regulator (BCER) all instances of black smoke that exceeds 15 minutes in duration and provide operational details concurrent with such instances;   
• By Aug. 15, 2026, submit a report completed by a qualified professional to the BCER that identifies the root causes of the emission of black smoke and measures to prevent the emission of black smoke; 
• By October 15, 2026, identify and implement measures to prevent the emission of black smoke based on the root cause analysis as required by the report; 
• For the months of October 2026 to March 2027, submit a monthly report to the energy regulator BCER completed by a qualified professional that assesses the effectiveness of the measures implemented .

‘I want to have a family’: community members concerned about potential health impacts

For some community members, the black smoke and presence of other potential pollutants are a source of great concern. 

The Narwhal and Point Source spoke to a young resident who we are calling Avery Sutherland, to keep her name confidential and protect her identity. Kitimat is a small town where LNG Canada is a significant employer and a major donor to local causes, and criticism is often seen as a threat to that.

Avery Sutherland said she tried on multiple occasions to get answers to questions about potential health concerns, but LNG Canada representatives would not respond.

“As a young person, I want to have a family,” she said in an interview. “There’s been a lot of back and forth I’ve seen over the last couple of years at different talks that LNG [Canada] gives, where they refuse to directly acknowledge the studies that have been done on the impacts of flaring on women who are pregnant and their children, and how that often leads to like more birth complications and more premature births.”

In response to questions about this, the regulator spokesperson said: “It is important to note for the benefit of residents of Kitimat that air quality measurements in the Kitimat Valley have remained below B.C. Ambient Air Quality Objectives since LNG Canada received its air discharge permit.”

But some critics claim the air quality monitoring program is insufficient.

“The current ambient air pollution monitoring is not sufficient to get a real handle on what the health implications are for the people that are living close to this facility,” Tracey Saxby, executive director of environmental non-profit, My Sea to Sky, said in an interview. “When you dig into the data you realize that there aren’t enough sensors, they aren’t gathering data in the right places and not enough of the sensors are continually operating.” 

The Canadian Association of Physicians for the Environment has said the facility’s flaring activity has exposed residents to “health-harming chemicals, including black carbon and benzene.”

“They are not consistently monitoring for some of the most harmful pollutants, like benzene,” Saxby said. “These are big monitoring gaps.” Health Canada has labelled benzene a known carcinogen since 1993.

In 2024, the U.S.-based Bullard Center for Environmental and Climate Justice published a report highlighting how LNG export facilities degrade air quality by releasing pollutants known to cause respiratory illnesses, cancer and birth defects from prolonged exposure.

Scientific studies have shown that burning gas also releases other toxic pollutants as a result of incomplete combustion, such as volatile organic compounds, nitrogen oxides, sulfur dioxide, polycyclic aromatic hydrocarbons and fine soot particles, which are directly associated with respiratory and cardiovascular diseases and risks to fetal development.

“When you see this kind of pollution, it’s a sign that the flare isn’t being operated correctly and usually that comes with a lot of other emissions that are actively being released that are not visible to the naked eye,” Doty explained.

“It’s likely that the real world pollution levels are far worse than the picture painted by the current data,” Saxby said. “Even though the existing data is very sparse, it shows worrying spikes in benzene levels that raise a lot of questions about the health impacts from the LNG Canada facility.”

As The Narwhal and Point Source recently reported, LNG Canada originally told the regulator it would operate its facility without routine flaring — and then quietly removed this commitment months before commissioning. 

Sutherland wishes the consortium that owns LNG Canada was more forthcoming with information. Its presence in the community has been divisive for as long as the facility has been in development, which means for young residents like herself, it’s been a factious issue for most of their lives. 

“When I was growing up, there were schoolyard and classroom arguments about this since as long as I can remember,” she said of the facility, which was proposed in 2013.

James Smith, another Kitimat resident whose name has been changed to protect his privacy, worked at the plant during construction. He said while he was expecting problems to occur at the facility, he didn’t predict the scale of the impacts. 

“I wasn’t expecting the black smoke,” he said. 

Smith said he’s experienced excessive noise and bad smells at his house since the facility started operations and on multiple occasions found his yard covered in a thin film of black residue.

Doty said the ongoing problems suggest to him the facility’s problem with its flare tip could be causing the black smoke.

“Flares like this should be operating with about 98 per cent combustion efficiency, but there is no way that the flare is operating with anything close to that efficiency,” he said. “If there’s too much pressure going to it, you’re never going to get things to combust properly — and that seems to be what is happening at LNG Canada.” 

In response to questions from The Narwhal and Point Source, the regulator spokesperson noted: “The causes of the black smoke events have not yet been definitively determined.” 

‘Truly massive’ invisible emissions

On top of the elevated levels of flaring at the LNG Canada export terminal, there are increasing concerns about the facility routinely releasing natural gas into the atmosphere.

Natural gas is mostly composed of methane, which is an invisible, odorless and an extremely potent greenhouse gas. When released directly into the atmosphere it is 80 times more powerful than carbon dioxide for its short-term warming impact on the climate.

“If people could actually see the invisible emissions that are being released from the LNG Canada facility that are detectable with an optical gas imaging camera, it would really blow them away,” Doty said. He monitored emissions at the Kitimat facility with a camera.“The emissions that could not be seen with the bare eye were shocking. They were truly massive.”

Doty said the emissions — both visible and invisible — could have “very negative health implications for nearby communities and downwind receptors.” 

“If I was living nearby, I would be very concerned, and I would want the plant shut down, at least in the short term, while it is re-engineered,” he said. He noted the unburned gas could contain volatile organic compounds such as benzene and butane, in addition to the climate-warming methane.

“At the moment, the program to monitor ambient air pollution in the area isn’t effective and doesn’t have enough monitors in place to truly calculate how air quality is being impacted,” he said.

The Narwhal’s reporters are telling environment stories you won’t read about anywhere else. Stay in the loop by signing up for our free weekly dose of independent journalism.

When a Michigan court shot down Enbridge’s plan to bury a section of its aging Line 5 pipeline in a concrete tunnel under two Great Lakes, Ontario Premier Doug Ford responded with a pipeline pitch of his own.  

“The fuel that powers Ontario’s economy should never be put at risk because of decisions made in another country,” Ford wrote in a post on X (formerly Twitter) on Aug. 1. “That’s why we’re building the Northern Shield Energy Corridor — a new Canadian pipeline, made with Canadian steel, by Canadian workers, exclusively within Canada’s borders.” 

Summary

• The Michigan Supreme Court cancelled the state regulator’s approval of Enbridge’s Line 5 tunnel project, telling it to reassess potential harm to two Great Lakes regions.
• Ontario Premier Doug Ford said the decision highlighted a need to build a new all-Canadian pipeline from Alberta to Ontario.
• Ford’s warnings about relying on energy “decisions made in another country” come as his government continues to push natural gas expansion, and the province increasingly relies on American supply.

His comment came a day after the Michigan Supreme Court ruled in a 6-1 decision against the state commission’s approval of Enbridge’s plan to build a tunnel under the Straits of Mackinac, a narrow, fast-moving waterway that joins Lake Michigan and Lake Huron. The purpose would be to bury a portion of the 73-year-old pipeline, which is currently exposed on the lakebed. 

The pipeline is 1,038 kilometres long, roughly the driving distance between Windsor and Timmins, Ont. It carries crude oil and natural gas liquids (such as propane and butane) from Superior, Wisconsin, passing through Michigan on its way to refineries in Sarnia, Ont.

The court found regulators hadn’t properly studied the environmental harm the project could cause to the lakes before approving it in 2023. Justices said the regulator must study not just the environmental impact of the underwater tunnel, but also how the tunnel would extend the lifespan of the pipeline and what the environmental consequences of that may be. Indigenous nations have said it will increase the risk of oil spills and increase greenhouse gas emissions from the fossil fuels it transports. 

“It is impossible to prevent or mitigate an environmental risk without understanding the nature of that risk,” the justices wrote.

As a result, the project’s approval is now cancelled, with the court ordering the commission to redo its review. The ruling doesn’t shut Line 5 down, but delays efforts to repair it and keep it in commission. 

Enbridge spokesperson Ryan Duffy called the decision disappointing in a statement to Bridge Michigan, saying the company remains committed to “the safe and responsible operation of Line 5,” while it reviews its legal options. 

Michigan Gov. Gretchen Whitmer, who has long fought to shut the pipeline down altogether, said “the pipeline is a ticking time bomb,” pointing to Enbridge’s 2010 spill in the state’s Kalamazoo River, the worst inland oil spill in U.S. history. 

Indigenous communities and environmental groups that brought the case to court celebrated it as a win for the Great Lakes.

Ford took a different route, using the court decision to re-up a pipeline concept he announced with Alberta Premier Danielle Smith in July. The Northern Shield Energy Corridor is a proposed 3,300-kilometre line to carry crude oil from Hardisty, Alta., through Saskatchewan and Manitoba to Sarnia.

If built, Northern Shield would retrace some of the route of the long-dead Energy East proposal from TransCanada, before the company scrapped it in 2017, citing regulatory delays and falling oil prices. That proposal also met significant Indigenous opposition.

Ford has framed it as an all-Canadian pipeline that would be immune to the kind of cross-border legal fights now delaying updates to Line 5. Northern Shield is undergoing a feasibility study, due by the end of the year, with no confirmed cost, timeline or construction approval.

That proposed route of Ford’s new pipeline ends in the same place Line 5 does: Sarnia, next to Aamjiwnaang First Nation. Chief Janelle Nahmabin told The Narwhal her community is “closely following” the discussions around Line 5 and the Michigan court decision. 

“While governments continue to debate energy security and future infrastructure, it is important that First Nation rights, environmental protection and community health remain at the centre of those discussions,” she wrote in an email. 

She pointed to an unresolved crisis in her community over benzene air pollution from industry, and a pipeline spill near Aamjiwnaang’s land into the St. Clair River in March 2026 as issues that need to be addressed before a new pipeline is considered. She said that these “cumulative impacts of industrial development” were the result of “decisions being made elsewhere.” 

“Communities that have carried disproportionate environmental burdens for decades should not be asked to shoulder even more,” she said.

Ford’s pitch for domestic supply comes amid growing reliance on U.S. gas

Ford’s warnings about relying on energy “decisions made in another country” come as his government continues its longstanding push to expand natural gas use, which increasingly relies on American supply. 

Natural gas is largely made up of methane, a potent greenhouse gas that traps heat in the atmosphere. It is the primary source of heating for three-quarters of homes in Ontario.

According to Ontario’s Independent Electricity System Operator, natural gas accounts for nearly 30 per cent of the province’s total generating capacity, up from 28 per cent in 2020. The operator attributes that growth largely to nuclear facilities being taken offline for refurbishments as well as rising electricity demand. 

Ontario is underlaid with a network of pipelines supplying natural gas for heating. According to the province, 3.6 million homes and 160,000 businesses rely on natural gas.

Per analysis by the Canada Energy Regulator, Ontario’s historical reliance on natural gas from Alberta has declined as western producers focus on western U.S. markets. Meanwhile, production in the U.S. northeast has increased, making importing gas cheaper for eastern provinces. As a result, as of 2009, Ontario has become a net importer of gas from the U.S.

Between 2015 and 2020, the most recent data available, imports at three key crossings into Ontario increased by 31 per cent, with most coming through Niagara.

Ontario’s ties to natural gas have deepened under the Ford government

This increase in U.S. natural gas imports is compounded by recent provincial decisions that ensure natural gas remains a key part of Ontario’s energy mix. 

In December 2023, the government took the unprecedented step of overruling the independent Ontario Energy Board after it ordered Enbridge Gas to stop passing the cost of new gas hookups on to homeowners’ monthly bills. Documents obtained by The Narwhal through freedom of information requests showed Enbridge staff in frequent contact with officials in the premier’s office in the lead-up to that decision, and Ford personally called Enbridge to discuss a stalled gas connection. 

Meanwhile, a growing number of Ontario municipalities, including Guelph and Waterloo Region, have pushed back against a long-standing provincial rule that lets Enbridge Gas build pipelines under municipal roads and other public land for free. Enbridge Gas has these decades-long free-access agreements with more than 340 municipalities across the province.

When Guelph and Waterloo Region refused to renew their agreements last year, the dispute went to the Ontario Energy Board, where it is still being deliberated. Energy Minister Stephen Lecce said the province isn’t considering changing the rule despite the municipalities’ calls to do so. 

As all of this plays out, including the Line 5 saga, Enbridge has told investors it expects to return tens of billions of dollars to shareholders over the coming years, in part because of the strength of continued gas demand growth in Ontario.

Updated on Aug. 7, 2026 at 2:026 p.m. ET: This story was updated to include a statement from Aamjiwnaang First Nation Chief Janelle Nahmabin sent to The Narwhal after publication.

The Narwhal’s reporters are telling environment stories you won’t read about anywhere else. Stay in the loop by signing up for our free weekly dose of independent journalism.

Summary

• As polls suggest a majority of Canadians support building new pipelines, the Alberta government is proposing a new pipeline to the West Coast to help boost production in the oilsands.
• The terms of the pipeline proposal name Alberta and the Canadian government together as majority owners, suggesting taxpayers will foot much of the construction bill.
• Pipelines are very expensive to build. A recent analysis of the federal government’s Trans Mountain pipeline, which is already operational, showed that the pipeline’s revenues aren’t high enough to cover its construction and debt costs, making it a money-loser for taxpayers.

Pipelines, pipelines, pipelines. No matter how you feel about them, it’s hard to escape news of them lately. 

In July, the Alberta government announced it is formally proposing another pipeline to the West Coast. On the weekend, the federal government took another step towards designating the pipeline as a project in the national interest, meaning environmental assessments and other parts of the approval process could be fast-tracked.

Recent polling shows the majority of Canadians — 63 per cent according to the Angus Reid Institute in July — support that new pipeline from Alberta to B.C.

Why? Mostly for economic reasons. A majority told pollsters they were convinced by the argument that Canada needs to diversify its oil markets away from the U.S., while half said oil is just generally important to the economy. Forty-five per cent said the project would create jobs. 

The economic forecast, though, isn’t quite that simple. There’s still the question of who’s going to pay for it. A poll commissioned by the Pembina Institute and conducted by Probe Research in April found a majority of Albertans — 61 per cent — say they don’t want to spend taxpayer money on a new pipeline.

It’s increasingly clear: many Canadians say they do want a new pipeline, but they don’t want to pay for it. Companies aren’t exactly lining up to build new pipelines by themselves either. That raises a question: why?

So what are the economics of a pipeline in Canada? Do they make money? Here’s what you need to know.

How much do pipelines cost to build?

No one is going to build a pipeline on a shoestring. These are multibillion-dollar projects, often crossing multiple provinces. Even expanding an existing pipeline, or building along an existing pipeline route is a huge endeavour involving tens of thousands of people working on the project.

Take the Trans Mountain Expansion project, as an example. That increased the capacity of an existing pipeline, built in the 1950s, from Alberta to the West Coast. That expansion project ultimately cost taxpayers $34 billion — notably, that’s almost $30 billion more than initial estimates. 

The latest pipeline idea making headlines was proposed by the Alberta government, with an estimated cost pegged at between $35.2 billion and $43.7 billion. That proposal was brought forward alongside the federally owned Trans Mountain Corporation, which will lead the project, and Pembina Pipeline Corporation (which is not connected to the Pembina Institute that held the poll). 

Under the proposed partnership, Trans Mountain and the Government of Alberta — through the Alberta Petroleum Marketing Commission — would hold a majority interest. 

So who would actually own it? Well … taxpayers, in a way.

How much have taxpayers spent building pipelines in the past?

It varies. Canadian taxpayers have been on the hook for billions since the Government of Canada purchased the Trans Mountain pipeline in 2018.

And maybe that’s okay. Some would argue that pipelines are infrastructure, much like highways or railways. Others disagree that billions of dollars of public money should be put toward increasing oil and gas infrastructure.

Nonetheless, it continues to happen. TC Energy’s cancelled Keystone XL expansion was backstopped by Alberta taxpayers to the tune of $1.5 billion in 2021.

And it’s happening again. Alberta’s government has already contributed a little more than $18 million to its latest pipeline plan, saying the money went to early planning work “including preliminary engineering, cost estimates, economic modelling, early Indigenous engagement with communities and development of the proposal for federal consideration.”

The Alberta government calls it a “myth” that it will pay for the entirety of the pipeline, saying, “Now that this preliminary work is done, we will work alongside Trans Mountain and Pembina Pipeline to move this project ahead.” But Pembina Pipeline currently has only a 10 per cent stake in the project.

So, in the end, it appears if the West Coast pipeline project moves ahead, it will be governments — and taxpayers — who foot much of the bill.

“I am quite comfortable that this is a good investment for Canadian taxpayers,” federal Energy and Natural Resources Minister Tim Hodgson told CBC in July.

How does a pipeline operator make money?

Whether pipelines are owned by companies or governments (and taxpayers like you), they charge fees for companies to move their products. The fees paid to use pipelines by companies such as oil producers are called tolls or tariffs. 

The Canada Energy Regulator oversees pipeline tolls, saying it ensures “they are just and reasonable.”

According to the regulator, tolls “cover the company’s cost of service, including a fair and reasonable return to pipeline investors.” Rates vary based on many factors: whether there’s a long-term commitment to shipping, how far, what the product is and how much of it.

The Trans Mountain expansion ended up costing so much that the tolls it charges customers to move oil are higher than expected. Still, according to the International Institute for Sustainable Development, only $15.4 billion of the $34-billion cost of the pipeline is covered by the tolls it charges.

Does running a pipeline actually make money?

Let’s look at Trans Mountain Corporation as an example — that pipeline we all own together. 

The company says it is now profitable. It reported its net income for 2025 was $556 million — up from $5 million the year before.

It’s what Minister Hodgson described to CBC as “generating oodles of cash.” 

But that claim has raised some eyebrows. And untangling it is complicated. 

The Trans Mountain Corporation is a wholly owned entity of another company, Canada TMP Finance Ltd., which is itself a subsidiary of Canada Development Investment Corporation, the entity which holds the Government of Canada’s investment in Trans Mountain. Still following? 

Let’s do it in the opposite direction. The Government of Canada owns a Crown corporation. That corporation has a subsidiary, which then in turn owns Trans Mountain Corporation. Hopefully that helps.

The debt of the expansion, and the interest on that debt, isn’t paid off. But Hodgson can claim the pipeline is profitable because of the confusing corporate structure of which Crown corporation holds its construction debt and pays the interest, and which takes in the tariffs, according to a report from the International Institute for Sustainable Development.

The author of the report described Trans Mountain’s profit claims to The Tyee as a “misrepresentation of finances.”

Trans Mountain Corporation did not respond to questions from The Narwhal by publication time.

But a company’s balance books aren’t the only way of looking at it. Industry advocates argue pipelines generate money in other ways too, including tax and royalty revenues and making oil prices more competitive.

For example, a 2024 report from a group created for Alberta credit unions argued the Trans Mountain expansion project resulted in a significant increase in access to markets for Alberta oil and that access significantly narrowed the price difference between a type of Western Canadian oil called Western Canadian Select and a type sold out of Texas called West Texas Intermediate. The report estimated this had already increased revenues by about $10 billion in the first six months the pipeline expansion launched.

There’s little doubt that producing and exporting oil and gas makes money for Canada — and especially for oil and gas companies themselves. But many have argued a fuller accounting would include the significant costs of the health risks, environmental degradation and other damage that comes from increasing carbon pollution from the burning of fossil fuels.

What are the costs of carbon pollution from increasing oil production?

Fossil fuel production is driving climate change and the consequences are being felt today. Life is more expensive, cities have dirtier air from wildfires, deadly heat waves and other extreme weather are more common, First Nations are disproportionately threatened with disasters and Canadians are more at risk of poverty, heart disease, cancer and premature death.

As The Narwhal has reported, it’s possible, at least broadly speaking, to compare the economic output of fossil fuels with health costs. The federal energy regulator, for example, has reported the total value of crude oil exports from Canada was $138 billion in 2024. A Health Canada report that same year found the total cost of health impacts attributable to air pollution in 2018 was $146 billion. The cost of many foods produced here is also rising as farming becomes less predictable. 

Estimates vary, but the short answer is climate change is expensive. A 2022 report from Queen’s University projected trillions of dollars in losses in Canada due to climate change this century, with the greatest contributor to that change being the burning of fossil fuels.

Does Alberta produce enough oil to fill a new pipeline?

Trans Mountain is currently “Canada’s only pipeline system transporting oil products to the West Coast.” The company says its 1,200-kilometre pipeline network has room for 890,000 barrels of petroleum products to be shipped each and every day. 

The new pipeline proposed by the Alberta government would be capable of transporting one million barrels of crude oil per day from the Edmonton area to the West Coast.

If it goes ahead, that would significantly increase the network of pipelines leading from Alberta.

There are already several other pipeline systems in use — leading to other locations in the U.S. and eastern Canada — and according to the Alberta Energy Regulator, all of them together could carry 5.4 million barrels per day. 

Currently, Alberta produces an average of more than four million barrels of oil per day. That suggests Alberta’s oil production stands to increase substantially if a new pipeline is going to be filled each and every day. 

Meanwhile the International Energy Agency has predicted global demand for oil from combustible fossil fuels may peak as early as 2027 — raising questions about the long-term outlook for expanded oilsands production.

— With files from Drew Anderson and Carl Meyer

The Narwhal’s reporters are telling environment stories you won’t read about anywhere else. Stay in the loop by signing up for our free weekly dose of independent journalism.