Governments are preparing to absorb a risk that highly profitable oil companies have declined to take. That is not a technical detail of project financing. It is the clearest signal yet of a fraught economic strategy for Canada’s near future – one that puts resource extraction at the centre of national development.

A strategy, not a project

On July 2, the federal government and British Columbia committed billions in public investment to liquefied natural gas development, mining and other extractive industries, and to expanding the Roberts Bank port terminal south of Vancouver, later identified as the marine terminus for the new Alberta pipeline. Later that day, the West Coast line was revealed. The following week, Alberta and Ontario proposed a second pipeline, also without a private proponent and also likely to require substantial public money.

Whether or not that second line is ever built, the sequence confirms that these are not separate infrastructure decisions. They are part of a broader commitment to an extractive economy: the federal Major Projects Office is now fast-tracking 23 “nation-building” initiatives worth well more than $130 billion across liquefied natural gas, nuclear, mining and transportation.

A bet the industry won’t make

Ottawa has formally proposed listing the pipeline as a “project of national interest.” Alberta’s submission puts the cost at $35.2 billion to $43.7 billion, excluding escalation and financing costs, and assuming regulatory savings. It would be built by a new entity jointly owned by Trans Mountain Corporation, Alberta’s Petroleum Marketing Commission and Pembina Pipeline, a Calgary-based company whose non-binding 10% stake is the only private participation. Taxpayers would carry the rest, and there is still no finalized financing plan.

The pipeline is also only part of the public bill. Add the Roberts Bank terminal at roughly $10 billion and the linked carbon-capture project at $16.5 billion officially, and more than $20 billion by recent estimates, and allow for overruns of the kind Trans Mountain produced, and the public commitment could exceed $100 billion – an estimate from market-oriented critics, not climate advocates.

The project includes an Indigenous equity purchase right, to be drawn from the two governments’ shares, but its size and timing remain unspecified. First Nations along the southern route say they were not consulted before the announcement, and 14 First Nations are challenging the fast-tracking law in court.

Canada has been here before: Ottawa acquired the Trans Mountain system in 2018 after private investors stepped back. The expansion ultimately cost about $34 billion, more than six times the original estimate.

The reluctance of industry is not hard to explain. Bitumen is among the highest-cost sources of oil, highly sensitive to price swings and exposed to declining long-term demand as decarbonization accelerates. The International Energy Agency expects global oil demand to peak by 2030, with supply capacity running well above it. With the West Coast line unlikely to be complete before the early-to-mid 2030s, the project risks becoming a stranded asset.

Companies are behaving accordingly. Through the recent price boom, the four largest oil-sands producers cut investment – to $15.9 billion a year across 2021 to 2024, down from $27.9 billion a year in the 2011 to 2014 boom – while sharply increasing dividends and share buybacks. Capital is being returned to shareholders, not committed to new production. If the industry believed in the economics of expansion, it would be leading the investment.

Who this economy is for

Ottawa and Alberta describe the West Coast line as the way to build a strong, prosperous, sovereign Canada. But the record of the last boom complicates these claims.

A report by the Alberta Federation of Labour and Canadians for Tax Fairness found that between 2021 and 2023, the oil and gas industry earned $135.2 billion in operating profits while paying $43 billion in wages – $3.14 in profit for every dollar paid to workers, up from $0.92 in the previous boom. The sector employs roughly 30,000 fewer people than in 2014. And the owners collecting those profits are largely not Canadian. The report estimates that the big four producers are 73% foreign-owned and 60% U.S.-owned, with an estimated $58 billion in dividends and buybacks flowing to foreign owners between 2021 and 2024.

An industry that produces more with fewer workers, invests less, and sends most of its returns abroad is a weak foundation for shared prosperity – and a strange candidate for one of the largest public commitments of the coming decade.

The rollbacks are part of the plan

You might wonder about the environmental safeguards in place, especially as the urgency of climate change is evident all around us. Projects on this scale face barriers under existing environmental rules. So, those rules are being loosened. Canada and Alberta signed a cooperation agreement to streamline and add flexibility to impact assessment; their implementation agreement commits both governments to regulatory frameworks enabling substantial oil-sands growth. The federal government is now proposing faster approvals, expanded pre-designated development zones, and a narrower scope for environmental assessment.

The retreat extends beyond permitting: over the past year, Ottawa has scrapped or weakened the consumer carbon price, the planned oil and gas emissions cap, the electric vehicle mandate, the clean-electricity regulations and the industrial carbon price. Deregulation and environmental rollbacks are not incidental to this strategy. They are what makes it possible – and they build higher emissions into it by design.

The environmental case offered in return is the multibillion-dollar plan to capture and store 16 million tonnes of carbon dioxide a year from the oil sands by 2045. The so-called Pathways project – designed by an alliance of five major oil-sands players – would itself require substantial public funding. Reducing production emissions is worthwhile and should be required of the industry. But about 80% of a barrel’s life-cycle emissions come from burning the fuel, not from producing, refining and transporting it – which is what carbon capture addresses.

Pathways is to capture six million tonnes a year by 2035, while the pipeline is sized to carry a million barrels a day – 365 million barrels a year, or about 157 million tonnes of carbon dioxide when burned. So the “decarbonized oil” the prime minister has invoked would, even if every commitment in the package is met, be oil whose emissions are lower by less than a 10th. In exchange, the companies get a slower rise in carbon-price stringency.

The path not taken

Capital markets respond not only to subsidies but to perceived direction. When governments commit to fossil expansion while delaying climate policy, they signal that Canada’s economic future remains anchored in extraction – shaping where investment flows, which technologies scale and which regions are seen as growth areas while eroding the policy certainty that clean industries need.

The contrast with other jurisdictions is stark. Across Europe, parts of Asia and especially China, governments are pursuing electrification strategies built on renewable energy, grid expansion, electric mobility and low-carbon industry. These are not environmental side projects; they are 21st-century industrial strategies designed to win in a decarbonizing economy. Ottawa’s recently proposed electrification strategy will be credible only if matched by fiscal and regulatory decisions of comparable weight.

Fiscal capacity is finite. Hundreds of billions of dollars committed over the coming decade to extractive infrastructure, nuclear development and military expenditure will press on everything else – healthcare, education, affordable housing, climate adaptation and the care economy, sectors already facing hiring freezes and service reductions even as capital commitments are made elsewhere.

Political capital is finite, too. Aligning closely with the governments of Danielle Smith and Doug Ford eases agreement on these projects while making a different course harder to take later. Pipelines built in the 2030s will still be seeking returns in the 2060s. That is the definition of lock-in, at a time when Canada is already off-track for its climate targets and when extreme heat, wildfire smoke, floods and drought are already damaging health, infrastructure and public finances.

A better bet

Canada does need an ambitious strategy for a low-carbon future – one that diversifies trade, strengthens economic sovereignty and builds at scale. And the same public investment and political capital could go to renewables, a national electricity grid, storage and efficiency, building retrofits, electrified transportation, a circular economy, climate resilience, the care economy and a just transition for the workers and communities that depend on extraction. All this builds value as the world decarbonizes, employs more people per dollar, and cannot be stranded by a shift in global demand.

Before Canada commits another generation of public money to the industries of the last century, governments should be able to explain why this is a better investment in the country’s future than the alternatives competing for the same support. So far, they have not.

Ricardo Grinspun is professor emeritus of economics at York University and a member of Seniors for Climate Action Now!

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But now, five years later, a family of Wyoming oil tycoons is bringing the Keystone concept back from the dead — and the Trump administration is signaling its support. Last week, President Trump signed a presidential permit for the so-called Bridger expansion pipeline, which would likely deliver oil from the carbon-intensive Alberta tar sands to a pipeline hub in central Wyoming, 647 miles away. From there, the oil could move through other pipelines to key refineries as far south as the Gulf of Mexico.

“Slightly different than the last administration,” Trump said ⁠at the White House last Thursday when he signed the presidential permit. “They wouldn’t sign a pipeline deal, and we have pipelines going up.”

The presidential permit gives the project the green light to transport oil across international borders, and it’s only the latest step in what appears to be a fast-tracked timeline for the revived tar sands pipeline. Last month, the federal Bureau of Land Management announced that it would begin conducting an environmental review of the project on an expedited schedule. (The Trump administration has shortened many of the environmental review processes required for pipeline construction.) Bridger Pipeline, the company behind the project, says it wants to begin construction next year and start moving oil in 2028.

The pipeline would carry at least 550,000 barrels of crude oil per day. That’s only about two-thirds of what Keystone XL would have carried, but it could expand to a peak capacity even larger than what was originally planned — more than 1 million barrels a day. The similarity between the new pipeline’s path and Keystone’s has led some opponents to call the successor “Keystone Light.” The Canadian portion of the new pipeline would be built by a company called South Bow, which was spun off from TC Energy, the company behind the original Keystone XL line.

The proposed pipeline would be one of the biggest new fossil fuel developments of Donald Trump’s second presidency. It comes at a time of growing oil production in Alberta and skyrocketing global crude prices due to the war the president is waging in Iran. The project is being pushed by the True family, a clan of oilmen with a long history of drilling in the Rockies — and a history of oil spills from pipelines across the region.

“We know that there is limited pipeline capacity to move Canadian crude oil, and we have extensive experience in the Rocky Mountains,” said Bill Salvin, a spokesperson for Bridger Pipeline, the True family pipeline company proposing the project.

The True business empire dates back to the 1940s, when a wildcatter named Henry Alphonso “Dave” True Jr. began exploring for oil in Wyoming. He and his three sons expanded their company into a network of almost a dozen corporations that includes a drilling company, a network of local oil pipelines, a trucking company, an oil trading company, an oil equipment company, a geothermal energy firm, and a real estate company called Brick & Bond, according to a Grist review of corporate records. They also invested in cattle ranching, becoming some of the state’s largest landowners. One of True’s sons, Diemer True, served for two decades in the Wyoming legislature.

This corporate expansion has given the four-generation True family outsize influence in a state that doesn’t produce much oil but neighbors the massive Bakken shale formation of North Dakota, which is served by some of the True family pipelines. The family name is synonymous with oil in Wyoming, and True family members have become prominent donors to the University of Wyoming and to a conservative legal foundation in the region. The Trues have also run afoul of the federal government: Several members of the family engaged in a 10-year dispute with the Internal Revenue Service over what the government said was a strategy to evade some taxes by shuttling ranchland purchases between different companies. (The case ended in a multimillion-dollar fine against the Trues, which was upheld by an appellate court in 2004.)

“They’re very prominent, and their business interests have spread all around the West,” said Phil Roberts, an emeritus professor of history at the University of Wyoming and an expert on the state’s oil industry. He noted that families like the Trues have shifted away from oil production as the state’s fields have declined, investing in pipelines and oilfield services to maintain their revenue.

“Those fields have gotten really worn out, so they’ve had to diversify,” said Roberts.

Tad True, the grandson of the True who first struck oil in Wyoming, has led the family’s pipeline business for most of this century, expanding its network to more than 4,000 miles across Wyoming, Montana, and North Dakota. He argued as early as 2006 that more pipeline development was needed in order for regional oil producers to remain competitive, and in a 2012 testimony before the House of Representatives he said that the Obama administration’s regulations were blocking the pipelines needed for the fracking boom that was then in full swing. True spoke at the Republican National Convention the same year, accusing Obama of “playing politics” with the Keystone XL pipeline, which the then-president had rejected the previous year. (While the pipeline was primarily intended to carry Canadian shale oil to American markets, it would also have included an “on ramp” for crude from True’s part of the country.)

True’s company, Bridger Pipeline, has a history of oil spills. In 2015, one of the pipelines it operated ruptured underneath the Yellowstone River after fast-moving waters eroded sediment and rock from the riverbed. At least 30,000 gallons of crude oil streamed into the river, contaminating the water supplies of Glendive, Montana. The town had to truck in bottles of drinking water after some residents noticed an odor in their tap water. Then, just a year later, another pipeline operated by one of the company’s subsidiaries leaked 600,000 gallons into a stream in North Dakota — almost enough oil to fill an Olympic-sized pool. Another pipeline broke several years later, dumping 45,000 gallons of oil onto ranchland in Wyoming. The company ultimately paid $1 million in fines to the Montana Department of Environmental Quality for the 2015 spill and $12.5 million for the 2016 spill.

In total, there have been at least 42 spills as a result of pipeline operations by True subsidiaries since 2010. According to data collected by the federal Pipeline and Hazardous Materials Safety Administration, more than a third of those spills had detrimental effects on the environment or people. The data shows that the Bridger Pipeline company alone is responsible for seven of those spills in just the last three years. The most recent spill took place in March near Guernsey, Wyoming.

“That definitely sets off some alarm bells,” said Kenneth Clarkson, communications director with the nonprofit Pipeline Safety Trust. “It’s not acceptable to have one incident, and when we have this quantity, it’s definitely troubling.”

If the expanded Bridger pipeline ultimately carries tar sands oil from Canada, as appears likely, the environmental consequences of a spill could be dire. Given the thick, viscous nature of tar sands, operators mix a type of thinner — called a “diluent” in technical parlance — to help it flow through pipelines. In the event of a rupture, the diluent can easily evaporate, leaving behind a heavy, tar-like substance that sinks to the bottom of rivers and other waterways. That particular property of tar sands made cleanup of the Kalamazoo River particularly complicated after a different company’s pipeline burst in southwestern Michigan in 2010.

“We regret any spill from our pipelines,” said Salvin, the Bridger spokesperson. “Anytime oil gets out of the line, that’s unacceptable to us, so we do everything possible to keep the oil in the line.” He said that Bridger will employ “horizontal drilling” to tunnel under rivers and streams, which he said would reduce the risk of ruptures. Salvin did not say what type of oil the pipeline would carry, but confirmed it would be engineered for “mostly heavy crude” from Alberta; the Canadian portion of the pipeline will begin in the town of Hardisty, in the heart of Alberta’s oil sands.

He also said the company would use advanced technology to monitor for leaks. In the aftermath of the 2015 spill, when North Dakota’s then-governor Doug Burgum challenged Tad True to prevent leaks, True created an artificial-intelligence software called Flowstate that analyzes pipelines for potential ruptures. Salvin said the company now uses the software on all its pipelines and markets it to other operators as well.

Even though the new proposed pipeline is similar to Keystone XL in length and size, it will only cost $2 billion, far less than Keystone’s $8 billion price tag. That’s because its route will largely follow existing infrastructure and rights-of-way established by True Companies pipelines. Salvin said that the company has held a dozen landowner meetings and has secured surveying easements, or allowances to scout the land for construction, from 374 of the 376 private landowners along the pipeline route. Unlike Keystone XL, the route does not cross any federally recognized tribal lands.

“We’re very familiar with what happened with the previous project,” said Salvin. “Given that we have existing pipeline corridors that we have access to, that’s one of the reasons why this makes such commercial sense to us.” Salvin declined to offer details about the financing of the project, and such details are not publicly available because Bridger is a privately held company.

The project must still secure a number of state and local permits, but so far it isn’t having any trouble with the Trump administration, which has been aggressive in supporting new oil and gas development. The line cuts through Montana and Wyoming, including public land overseen by the Bureau of Land Management, which is leading the federal government’s review of the project under the National Environmental Policy Act. Although the law typically requires the preparation of a detailed assessment of the project’s impact on wildlife and waterways, the bureau has suggested it might fast-track the pipeline’s review.

Past studies have found that it typically takes federal agencies more than two years to complete an environmental impact statement, but the Bureau has indicated in public filings that it intends to publish a final impact statement by next May and make a decision on the project, allowing the company to begin construction by July.

Though True family members do not appear to be particularly close allies of Trump himself, they have given more than $4 million to Republican candidates and political action committees since 1977, according to federal records. A combined $12,000 went to Trump’s unsuccessful reelection campaign in 2020, the only apparent record of True financial support for the president. Furthermore, six members of the True family appeared on a 2022 endorsement list for Liz Cheney, the Wyoming politician who lost her reelection bid after she voted to impeach Trump.

The business case for the new pipeline rests on a number of big assumptions. The existing pipelines from the tar sands are running near capacity, but the Bridger proposal assumes that production in Canada’s oil hub will continue to increase. Many forecasters aren’t so sure; even with prices high, current projections show that production growth is slowing and may peak in 2030 at around 3.5 million barrels a day, well under what the proponents of Keystone XL anticipated.

Second, the pipeline would only carry oil to central Wyoming, not all the way to the Nebraska refinery hub targeted by the original Keystone XL pipeline. Another company would need to build another pipeline across Nebraska in order for the crude to reach the major oil refineries on the Gulf Coast. (Salvin said Bridger is “exploring options” for that segment.) Third, it’s unclear if those refiners will even want as much of the heavy Canadian crude oil that the pipeline would offer, since imports of similar oil from Venezuela have started to tick up following Trump’s kidnapping of Venezuelan leader Nicolás Maduro and subsequent negotiations with the country’s new leadership.

“To call this plan half-baked would be an insult to baking,” wrote energy lawyer and anti-pipeline advocate Paul Blackburn in a blog post last month. Blackburn is an advisor to Bold Alliance, the activist network that opposed the last Keystone XL proposal.

Many of the same activist groups that opposed the prior pipeline are getting ready to oppose this one as well. The Bold Alliance, which organized tribes and rural landowners against Keystone, has said it will litigate any attempt to extend a pipeline into Nebraska. Jenny Harbine, a managing attorney with the nonprofit Earthjustice, said her group is “keeping a close eye” to ensure federal and state agencies adequately consider environmental and safety concerns. The Bureau of Land Management and the Montana Department of Environmental Quality, which is coordinating its review with that of the federal government, closed an initial public comment period last week.

This article originally appeared in Grist. Grist is a nonprofit, independent media organization dedicated to telling stories of climate solutions and a just future. Learn more at Grist.org

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Bile duct cancer⁠ is rare, with only about 600 cases diagnosed in Canada each year. But in this town, located downstream from the Alberta oil sands, O’Connor was seeing rates that were far higher than expected. The mostly Indigenous population relies heavily on hunting, trapping and fishing for food, and they’d told O’Connor about changes they’d seen – a rainbow colour appearing on the surface of Lake Athabasca, a dwindling fish population and ducks that appeared unwell, he recalls. “It dawned on me: this is a community that’s suffering as a result of what’s happening upstream.”

O’Connor publicly called for investigations. In response, three physicians with Health Canada filed complaints against him with the Alberta College of Physicians and Surgeons, saying O’Connor was causing “undue alarm.” He was eventually cleared of any wrongdoing.

The provincial health authority and other groups carried out small studies over the next eight years, but the results were not definitive. Research on how environmental factors affect health can be difficult to do and requires substantial time and detailed, accurate data. That’s been an ongoing challenge in Alberta. And so the question remains: what exactly are the health risks for a community that sits close to major oil and gas infrastructure?

Twenty years after O’Connor first raised concerns, physicians, environmental advocates and community members in Alberta are still calling for more definitive monitoring and investigations into the health and environmental effects of Alberta’s oil and gas industry, not just in Fort Chipewyan but across the province. They say that this kind of research is long overdue and should be initiated now, as Danielle Smith’s government weighs its next steps with what to do with Alberta’s aging oil and gas infrastructure – the old wells, pipes and other dated infrastructure, often referred to as mature assets. Many of these lie in rural regions far from the oil sands and Fort Chipewyan, but also where there is less close monitoring.

The Alberta government published a report last year with recommendations about what to do with the province’s mature assets. The Smith government is expected to take more formal action based on the report later this year. But the report doesn’t call for closer monitoring of non-producing wells – a gap that has industry watchers and community advocates worried.

Amanda Bryant, a climate policy expert and manager of the Pembina Institute’s oil and gas program, says that vital information is being missed. She says the province should be collecting in-depth health and environmental data from all areas with non-producing wells. She wants that information to be collected and made available for analysis. The Alberta Energy Regulator and provincial health authorities do collect data, but not enough, she says. “I would be skeptical that we currently have enough data to be making the judgment that these wells are not posing a health risk. The research that there is shows that there is cause for concern, that there are potential health impacts.”

Better health research is “part of protecting the public, the public interest and the public good,” she adds.

Leaking legacies

Alberta is home to 275,000 marginal, inactive or decommissioned but unreclaimed well bores or surface locations, according to the government’s mature-asset strategy report. Many remain in a state of ambiguity: they no longer produce oil or gas – or else produce so little that they’ve outlived their economic value – but have not been declared inactive, because there’s no economic incentive to do so. Other wells have been decommissioned but have not undergone the required cleanup and restoration to meet the province’s standard.

For years, Alberta has followed the “polluter pays” principle: the party that causes environmental damage is responsible for bearing the costs of cleanup, remediation and compensation. But many companies responsible for abandoned wells have gone out of business. For those wells, the responsibility falls to the Orphan Well Association, a non-profit organization funded by industry levies. Every year, the Alberta Energy Regulator (AER) prescribes the amount for the levy, using a formula to calculate how much each company is required to contribute.

For the 2025/2026 fiscal year, the AER set a levy of $144.45 million. This falls far short of what’s needed for cleanup in Alberta. The Orphan Well Association estimates that the total cost to clean up the sites it manages is $1.12 billion.

In the meantime, wells that are no longer producing but not yet cleaned up remain as they were, and not being as closely monitored as environmental groups would like. The AER maintains public records on location and regulatory status of wells but does not regularly monitor their condition over time. In comparison, active wells undergo regular evaluations for methane leaks and other pollutants, which have been linked to asthma, cancer and cardiovascular issues. Non-producing wells are not without risk. A recent study from researchers at McGill University, published in the journal Environmental Science & Technology⁠, looked at non-producing wells across Canada and found that methane emissions appear to be seven times higher than government estimates.

This doesn’t surprise Paul Belanger, an environmental engineer who worked in the oil and gas industry in Alberta for more than a decade. He is now the science adviser to Keepers of the Water, an Indigenous-led collective formed in 2006 to protect the Arctic Ocean Drainage Basin, the massive land areas whose waterways drain toward the Arctic Ocean. Belanger is concerned by the number of non-producing wells and small pipes throughout Alberta that are not being monitored. “What we’ve got now is abandoned wells in remote areas that look, to me, like they’re going to be ignored forever,” he says. “There’ll never be the money. We don’t have enough whistleblowers or sentinels out there to report every site.”

Belanger believes that saltwater spills at old well sites is an under-recognized threat in Alberta. As wells age, they produce significantly more water than oil, which leads to corrosion and contaminants leaching into the surrounding soil and groundwater. “As we’re sitting here, 30,000 wells are corroding. Rust never sleeps,” Belanger says. “I think that risk is just growing every month.”

The cost of uncertainty

Non-producing wells and the associated health and environmental risks have not been well studied in Canada. There’s fairly limited research into the health effects of oil and gas infrastructure overall. These studies are expensive and time-consuming, require meticulously kept datasets, and are beset with the challenge of distinguishing correlation from cause. On top of that, this is a politically and economically sensitive subject, particularly in Alberta, whose economy depends heavily on the oil and gas industry.

The lack of a strong evidence base is no reason to assume that things are not harmful, says Stephen Wilton, associate professor and cardiologist at the Cumming School of Medicine at the University of Calgary, where he is also co-director for planetary health. “In my mind, there’s enough evidence that we should be concerned,” he says. “One of the principles of public health is this ‘precautionary principle’: if you think there’s enough evidence of some harm and it’s plausible, then you should be taking precautions to avoid it.”

There is some evidence of harm. In one of the most significant studies to date in Canada, a 2021 report published in the journal Frontiers in Oncology showed a significant correlation between living in an area of dense oil and gas infrastructure in Alberta and the incidence of solid tumour cancers. The study is believed to be the first in Canada to look at cancer risk related to both active and inactive wells. The analysis showed that living close to one to three orphan sites was associated with an increased risk of solid tumours. The study showed correlation, not causation – that’s a huge limitation. Even so, the results raise the question of why. The authors concluded that it could be due to a lack of appropriate remediation or not being actively maintained by any proprietor, which could lead to increased environmental contamination.

What we’ve got now is abandoned wells in remote areas that look, to me, like they’re going to be ignored forever. There’ll never be the money. We don’t have enough whistleblowers or sentinels out there to report every site.

— Paul Belanger, environmental engineer

Other studies have shown that Alberta residents who live near oil and gas operations other than non-producing wells experience adverse health outcomes. In one report, published in JAMA Pediatrics in 2020, Calgary researchers found that people who lived within 10 kilometres of at least one fracking site were more likely to have children born small for their gestational age and have major congenital anomalies. In another study published last year, investigators found that 13% of Albertans live within 1.5 kilometres of an active well and 3% within 1.3 kilometres of a flare – and they have a 9% to 21% higher risk of experiencing cardiovascular or respiratory issues than people in the rest of the province. The closer a person lived to an oil or gas well, the greater their risk of these conditions, investigators found.

The study’s lead author is Martin Lavoie, a research scientist and data analyst at FluxLab, a leading methane measurement and technology development group at St. Francis Xavier University in Nova Scotia. Lavoie says that he was surprised by the challenge of getting reliable data on the location of oil and gas wells. “Sometimes the oil and gas industry doesn’t know exactly where is the well,” he says. “So imagine when you try to make the connection between [someone’s health] and a gas well, but you don’t know where is the gas well? Maybe it’s here. Maybe it’s 100 metres further south or west.”

Lavoie says that more accurate data would help researchers make better evaluations of things like methane emissions and health risks. “One of the recommendations to the regulator is just keep better track of what’s going on,” he says. “It’s one thing having the data, which we appreciate very much. But if the data is not accurate or could be more accurate, that’s a different issue.”

So far, most of the research looking at the health and environmental effects of non-producing wells has been done in the United States. In one study published in the journal ACS Omega, researchers reported harmful volatile organic compounds, including the carcinogen benzene, leaking from 48 abandoned wells in Pennsylvania. “In Canada, really surprisingly, we don’t have many studies on health related to the oil and gas industry,” Lavoie says.

Canadian researchers and community advocates want that to change.

In Fort Chipewyan, it is finally starting to change, but only after yet another crisis. In 2022 and 2023, Imperial Oil and the Alberta Energy Regulator failed to let communities know that wastewater containing arsenic, hydrocarbons and other pollutants was seeping into the watershed from Kearl Lake project outside of Fort McMurray.

The following year, the federal government announced nearly $12 million in funding over 10 years for a Fort Chipewyan Health Study. The community-led study, with the Athabasca Chipewyan First Nation, the Mikisew Cree First Nation and the Fort Chipewyan Métis Nation, will examine the impacts of the oil sands on community members’ health. It’s the first large-scale study of this kind in Canada.

Christina Frangou is a long-time health journalist based in Calgary, Alberta.

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On a sunny afternoon last August, Trans Mountain CEO Mark Maki donned a black jumpsuit to stroll atop a giant loading dock in Burnaby. Below, his company’s new pipeline pumped oil into tankers bound for the open ocean.

“We’re returning money now to the owner,” Maki said in a Global News segment. “Canadian taxpayers who are the shareholders of the system are reaping those benefits.” It seemed that Canada’s risky foray into pipeline ownership had finally proved to be a success.

What Maki didn’t mention was that the operating pipeline’s profit streak was relatively new, appearing after a sudden change had turned its months-long losses into gains. Little had changed on the ground. The amount of oil travelling through the pipe had remained mostly stable, as had its fees. Instead, the boon came on the company’s balance sheets, where millions in monthly interest payments vanished overnight.

“The only reason Trans Mountain looks like it’s making a profit is that most of the debt has been moved off their books,” says Thomas Gunton, a professor and director in resource and environmental planning at Simon Fraser University. “It’s a misrepresentation of finances on this project.”

The new balance-sheet profits are thanks to an employee-less shell company called TMP Finance, which holds billions of the pipeline’s debts on its account, shielding Trans Mountain Corp. from its interest costs. When all its debts are factored in, Gunton estimates the pipeline lost around $166 million in the first six months of 2025, a loss that raises questions about Ottawa’s ability to fulfil a pledge to direct millions from Trans Mountain’s revenues to climate initiatives.

Now those losses may be about to deepen. That’s because the oil companies that use the pipeline are fighting to reduce their rents by around $545 million each year. The oil companies’ 20-year pipeline contracts are already heavily discounted and set to cover only around half the pipeline’s cost. Further reducing the tolls could force taxpayers to cover an additional $11 billion in costs.

A model for more pipelines? Not quite.

Trans Mountain’s first string of sunny financial reports coincides with another pipeline debate – this time, about a proposed pipeline between Alberta and the north coast of British Columbia. In November, the province of Alberta and the federal government signed a memorandum of understanding pledging to remove obstacles for such a project. So far, the pipeline has no private proponent, but Alberta has promised to stand as the project’s proponent for now.

For some, Trans Mountain’s apparent financial success serves as a litmus test for Canada’s pipeline-building efforts. The federal government says the pipeline has helped strengthen the country’s energy sector and overall economy. Commentators have described the project as a “model investment” for its service to the oil industry, with some writing that Trans Mountain is “paying Canada’s rent.”

Such arguments require a closer look, says Amy Janzwood, an assistant professor in political science at McGill University. “There is this incredible revisionist history,” she says. “It’s like, ‘We bought TMX, look how profitable it can be.’ Profitable is not the word we should be using at all.”

Trans Mountain did not respond to The Tyee’s request for comment.

A sixfold increase in the cost to complete

Trans Mountain has one way to make money: it sells space in its pipe to oil companies, much like the owner of an apartment building rents rooms to tenants.

In 2012, Kinder Morgan, the former owner of the Trans Mountain pipeline expansion project, struck a deal with the project’s aspiring tenants. Their rents would cover the pipeline’s cost over their 20-year contracts and provide some wiggle room. At the time, the project was estimated to cost about $5 billion, and fees would fully pay for the project so long as it remained below $7.4 billion. Five years later and with no pipeline in the ground, Kinder Morgan started to get queasy. Its estimated cost had now hit its tenants’ price ceiling of $7.4 billion. If the price rose higher, Kinder Morgan would be on the hook for about 70% of the overruns.

“I think that they actually realized that it was no longer going to meet their internal commercial standards for return,” says Eugene Kung, a staff lawyer with West Coast Environmental Law. Kinder Morgan’s filing documents revealed that the company estimated the project’s costs would be closer to $9.3 billion – substantially higher than what its tenants would pay for.

The company suspended all “non-essential work” on the pipeline in spring 2018. Public financing seemed inevitable.

“Alberta is prepared to do whatever it takes to get this pipeline built – including taking a public position in the pipeline,” then-premier Rachel Notley said.

Before long, Kinder Morgan formally abandoned the project, selling it to the Canadian government for $4.5 billion. Ottawa did not carry out a new cost estimate of the project before the purchase, nor did the federal government attempt to renegotiate its shipping fees. “The government had all of those options open to them,” Gunton says. Canada’s parliamentary budget officer would later determine that the country overpaid for what it got.

“Kinder Morgan gamed us,” former finance minister Bill Morneau recently told a group of business students.

Construction expenses quickly ballooned. By the time the pipeline was completed in 2024, the cost to build it had increased sixfold from its original estimate to a total construction cost of $34.2 billion.

When is a loan not a loan? 

When Canada bought the pipeline in 2018, it created two corporations. Trans Mountain Corp., the more visible of the two, would build and operate the new and existing pipelines. A lesser-known company called TMP Finance Ltd. would hold the debt. Described by Kung as a “classic shell company,” TMP Finance has no employees and is run by Canada Development Investment Corp. It takes out loans from Canada’s coffers and passes money to Trans Mountain Corp.

Something important happens in those transactions: TMP Finance uses a major portion of its taxpayer-funded loans to “invest” in Trans Mountain Corp., buying a progressively bigger stake in the company in exchange for injections of funds.

Even though the money is originally borrowed from the public, Trans Mountain Corp. treats that money on its books like an investment, not a loan. So it doesn’t have to pay interest on that windfall. But TMP does.

When the pipeline began operations in May 2024, Trans Mountain had about $10 billion of that interest-free money from TMP Finance to work with. But with $27 billion in debt still on its books, it was still unable to earn enough from its shippers to cover the interest payments, even with the injection of money from TMP Finance.

That changed on December 13, 2024, when then-finance minister Chrystia Freeland provided a major government loan of $20 billion to TMP Finance. Most of the money was forwarded to Trans Mountain Corp. as an interest-free stake in the company. Trans Mountain then used the money to pay off an $18-billion bank loan, cutting its interest payments by more than half.

After the last infusion of cash, Trans Mountain’s profit streak began, and the company reported $148 million in profits in the first quarter of 2025.

Canadians should take Trans Mountain’s reported profits with “a spoonful of salt,” according to Mark Kalegha, an energy finance analyst at the Institute for Energy Economics and Financial Analysis. “Without that intermediary, the company would show debt that needed to be paid back,” he says. “There’s a lot of structuring behind this that made the entity appear more viable than it otherwise would.”

Unlike Trans Mountain Corp., which publishes its financial reports quarterly, TMP Finance’s books are opaque. Its financial information is amalgamated with the accounts of the Canada Development Investment Corp. Trans Mountain Corp. has told the Canada Energy Regulator it is not privy to TMP Finance’s accounts.

Absent customers, higher costs

Despite taxpayers fronting about 50% of the pipeline’s cost, oil companies shipping on Trans Mountain are not happy.

“Ironically, Trans Mountain is bad for everybody,” Gunton says. “It’s a lose, lose, lose.”

Though they pay a smaller share of cost overruns than Canadians, shippers’ fees to use the line are still 91% higher than anticipated in 2012, when the project was estimated at about $5 billion to build. According to Trans Mountain’s biggest customer, Canadian Natural Resources Ltd., the pipeline’s fees are “much higher than those of any other export pipeline.” Transporting oil on Trans Mountain costs about $9 more per barrel than using Enbridge pipelines that ship to the United States.

“The problem Trans Mountain has is that its tolls are higher than its competition,” Gunton says. “Even at the subsidized rate.” Those higher tolls might help explain another ingredient in Trans Mountain’s faltering financial picture: a dearth of so-called spot shippers – companies that pay a premium to use the pipe as desired but have no contractual obligations to the pipeline company.

If Trans Mountain’s contracted shippers are long-term renters, spot shippers are Airbnb bookings. In its financial projections, Trans Mountain assumed the pipeline would be 96% full, but the majority of that customer base hasn’t materialized, leaving the room mostly unused. “They’re hardly shipping any spot at all,” Gunton says. This means less money for Trans Mountain, but also for its committed shippers, whose pipeline tolls are reduced when the pipeline gets more spot customers.

For years, Trans Mountain and its contracted shippers have engaged in a document-heavy regulatory hearing to determine a “fair” fee going forward. But those hearings have now been put on hold for closed-door negotiations outside the regulatory process. If the shippers get their way, taxpayers could end up having to cover as much as $11 billion of legacy costs.

In its arguments, oil and gas company Canadian Natural Resources has said that government investment in the pipeline is to blame. “The government of Canada must consider broad social and political interests that are not the responsibility of investor-owned companies,” it said in a submission to the regulator, adding that the added “loss of financial oversight from capital markets and ratings agencies” means the pipeline is now operating in a new world of non-economic incentives.

Canadian Natural Resources argued that companies like itself shouldn’t face the consequences of those non-economic decisions.

Indeed, Trans Mountain has already shown a far greater appetite for risk than its privately owned predecessor, Kinder Morgan.

‘A broader macro-effect’ 

Proponents with big, costly projects that require many years to pay off – like pipelines – use a routine formula called net present value to determine whether their projects are worth the risk. The formula tells them how much their project needs to make every year to be considered “profitable,” given the uncertainties involved.

When Kinder Morgan first pitched Trans Mountain to regulators, it assured them it “would not proceed” unless it made enough money to make the risks worthwhile.

Among the biggest risks? The pipeline’s lifespan. Kinder Morgan decided it wasn’t willing to assume that companies would renew their 20-year contracts when the deals expire in 2043. Back when the project was expected to cost $5 billion, Kinder Morgan estimated it could pay off the project in 20 years with billions to spare. In other words, the project’s profit-making abilities were worth the risk.

Under its government owner, Trans Mountain still contends that its project is “profitable,” but it refuses to apply that standard formula to its new $36-billion price tag, relying instead on new accounting methods Gunton describes as “unconventional” in its responses to the energy regulator’s hearing on tolls. It also substantially upped its risk appetite and abandoned the expectation that the project will pay itself back in 20 years.

Some say that extended timeline is reasonable.

University of Calgary professor Trevor Tombe also adopted a longer payback time when he wrote a piece arguing that the project was “worth every penny.” Tombe’s analysis also didn’t consider the debt-shielding function of TMP Finance. “Every year this thing is profitable,” he said in a recent interview with The Tyee. Tombe added that he rejects claims that the pipeline brings in insufficient revenue.

Beyond the pipeline itself, Tombe points to the pipeline’s wider benefits. “A broader macro effect here vastly outweighs the cost of building the pipeline, even over just a couple of years’ time horizon,” he says.

The federal government agrees. In a statement to The Tyee, a spokesperson wrote that the pipeline has boosted Canada’s energy sector and “helped cement Canada’s position as a secure and reliable energy producer on the global stage.” The statement said the pipeline has made sourcing oil from Canada cheaper and quicker than doing so from the U.S. Gulf Coast. The statement did not acknowledge the comparatively cheaper prices to ship oil to the Gulf Coast through Enbridge’s pipeline.

With the addition of new pipeline space, proponents point to Trans Mountain’s potential to trim a long-held thorn in the industry’s side: the so-called discount between Canada’s oil and the standard price for oil in North America, which grew to almost $50 per barrel in 2018. When Canada’s oil is stuck without enough transportation routes, the discount tends to rise.

But Kalegha of the Institute for Energy Economics and Financial Analysis says it’s too early to confirm that Trans Mountain will play a lasting role. “I don’t see the data that supports that argument,” he says, noting that various factors can shape the discount. Notably, the discount had begun to fall prior to Trans Mountain’s start date.

Tombe notes that cheaper pipeline fees tend to curb the differential, putting Canada’s role as a pipeline owner and political actor in tension: it could try to raise the tolls in negotiations with shippers, but that could unravel its simultaneous efforts to boost Canadian oil production. “From the government’s perspective, there are a couple of things to think about,” he says.

Kalegha notes that bigger forces than pipeline fees could unseat Canada’s oil sector anyway, making its efforts to forestall the crash with new toll subsidies a losing bet.

Taxpayers inherit the risk

So long as its oil company tenants don’t go bankrupt in the next 20 years, Trans Mountain has a committed, albeit partial, income stream. But it faces major risks when its contracts come due in 2043, when, according to the International Energy Agency and other analysts, Asia and many other regions around the world will want less oil. That could erode Trans Mountain’s business case, leaving it with billions in unpaid debts and less income to pay them off.

“There’s a climate problem that’s been acknowledged across the board in different economies and different governments,” Kalegha says.

The International Energy Agency has predicted that China, which is currently the biggest buyer of Trans Mountain’s oil, will see its demand peak in 2027. Booming electric vehicle sales, including harder-to-electrify vehicles such as transport trucks, signal big changes on the horizon.

“If the transition unfolds and there’s no demand, then you start the question ‘Are these wise investments?’” Kalegha says. “Or should these funds be used for other projects that could have the same effect on the economy and prosperity of Canada?”

As a future oil pipeline to B.C.’s north coast looms on the horizon, Janzwood sees the government’s risky bet on Trans Mountain as a cautionary tale. “There’s actually a finite amount that corporations are willing to risk,” she says. “But when it’s the state, that doesn’t exist.”

If the gamble goes wrong, taxpayers could be left holding the bag.

Zoë Yunker is a Victoria-based journalist writing about environmental politics.

The post How creative accounting made Trans Mountain look profitable appeared first on Corporate Knights.

The data reinforce concern that the Danielle Smith government’s controversial renewable-energy moratorium two years ago and the regulatory uncertainty that followed it have been driving investors out of the province that previously led Canada in new project development.

The new numbers were published on LinkedIn last week by Jason Wang, senior analyst of electricity at the Pembina Institute. A chart based on data from the Alberta Electric System Operator (AESO) shows renewable-energy projects under development peaking above 25,000 megawatts between October 2023 and January 2024, dipping well below 15,000 megawatts by November 2024, then recovering somewhat before hitting a new low last month.

“This volume may rebound somewhat,” Wang wrote, citing an administrative deadline later this fall. “But without reversing some of its policy decisions, including in the current electricity market redesign, I expect to see more cold feet from investors.”

In May, Pembina said Smith’s decision to launch a constitutional challenge against the federal government’s watered-down Clean Electricity Regulations would add new uncertainty to the province’s electricity market. “At a time when other governments across this country and across the world are attracting investment in low-cost, secure, clean power, and modernizing their electricity grids to be fit for the needs of the next century, Alberta is introducing yet more uncertainty to its electricity market,” Wang said at the time. “This will further undermine investment confidence at the worst possible time.”

Later in the month, Pembina pointed to a wider series of new and prospective policies that were already bogging down the sector. “These include outright bans and ambiguous restrictions on areas of land where wind and solar projects can be built, new requirements relating to equipment recycling and land reclamation, and changes to transmission legislation, all of which will likely add new regulatory burdens and upfront costs to renewable energy developers,” the Calgary-based institute wrote. “It is notable that many of these new requirements are not being equally applied to other industries, including other energy sectors such as oil and gas.”

Wang’s latest analysis appeared just a couple of days before B.C. Hydro issued a call for 5,000 gigawatt-hours of electricity “from large clean or renewable projects in partnership with First Nations and independent power producers,” CTV News reported, equivalent to the output from the Site C hydropower megaproject. B.C. Premier David Eby took the opportunity to invite U.S. clean energy producers to turn their attention to Canada after Donald Trump described the wind turbines near his Turnberry golf resort in Scotland as “ugly monsters,” CTV said.

“We’re doubling down on renewable power, expanding our grid, and supporting First Nations leadership in energy development, all while helping communities and businesses access the clean electricity they need to grow,” Energy Minister Adrian Dix said in a statement.

In Nova Scotia, Premier Tim Houston announced that his province had designated Canada’s first four offshore wind areas. “With some of the top wind speeds in the world, Nova Scotia has the potential to become a clean energy superpower,” he said in a release. “With the right infrastructure, we’ll have the opportunity to send our wind west to power other parts of Canada. By becoming an energy exporter, we can secure long-term prosperity for Nova Scotians.”

On LinkedIn, Crux Energy Consulting founder and CEO Heidi Leslie warned that those projects may be more complicated than they seem. To hit its goal of five gigawatts of wind by 2030, she said the province will need grid transmission to get its power to market and commercial agreements that make sense to developers. “Nova Scotia has world-class wind resources,” and “offshore wind has huge potential,” Leslie wrote. But the projects will likely take 10 or more years to develop, they’ll require billions of dollars in investment per gigawatt, and experience in the United States suggests that the output from early projects will be expensive until supply chains mature and economies of scale begin to show up.

“Offshore wind isn’t plug-and-play,” Leslie said. “Developers need clarity on who will buy the power, how it will get delivered, and what policy support is in place. Without that, the designated zones are just lines on a map.”

At the same time, “this announcement matters,” Leslie added. “It gives developers, the province, utilities, and the federal government time to do the legwork: regulatory prep, environmental review, Indigenous engagement, fisheries planning, grid planning, supply chain development, etc. If we do that well, Nova Scotia can be ready to compete when offshore wind economics and market needs align.”

This article first appeared in The Energy Mix. It has been edited to conform with Corporate Knights style. Read the original article here.

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Drawing on longstanding pro-CO2 rhetoric in climate denialism, Policy Resolution #12 asks the government to scrap its decarbonization goals, remove the designation of carbon dioxide as a pollutant, and recognize the greenhouse gas as a “foundational nutrient for all life on Earth.”

“I think it has a very good chance of passing,” says Debra Davidson, a researcher in climate change impacts at the University of Alberta. “It’s not at all out of step with the position of Alberta’s United Conservative Party with respect to climate change mitigation and the energy industry for quite some time now.”

If it passes, the effect of the policy would be mainly symbolic, Davidson says, not only because it would be non-binding, but also because the Alberta government has already signalled that it has little intention of achieving its net-zero targets. Last year, for example, the province imposed a moratorium on large wind and solar projects, which led to 53 projects being cancelled and the estimated loss of $91 million in tax revenues. In the past five years, the UCP has also repealed the former NDP government’s carbon levy, opened the eastern slopes of the Rocky Mountains to coal mines, and withdrawn funding for a public transit project in Calgary.

As Stephen Legault, senior manager of Alberta energy transition at Environmental Defence, has said, the resolution is “already de facto policy.”

On the other hand, Alberta did release its Emissions Reduction and Energy Development Plan (ERED) in April 2023,  aiming for a carbon-neutral economy by 2050.  However, despite these commitments, “There is no evidence that Alberta has taken any action to regulate oil sands emissions as noted in the ERED plan,” says Simon Dyer, deputy executive director at the Pembina Institute. This summer, the Alberta Energy Regulator projected a 17% increase in oil sands production by 2033.

Instead, the provincial government “has focused on criticizing the federal plan to reduce oil and gas emissions,” Dyer says. Premier Danielle Smith is an outspoken opponent of Ottawa’s planned emissions cap and has launched a national “scrap the cap” ad campaign.

Even if the policy proposal mainly serves to underscore existing inaction on emissions, what’s truly notable, Davidson says, is “the degree to which it indicates a full-scale legitimation of disinformation.”

An energy policy based on fiction

The rationale for the proposal is largely erroneous. It takes a few grains of truth – that the carbon cycle is necessary and that carbon dioxide benefits plants – and couches them in the mistaken ideas that current CO2 levels are near their lowest in more than 1,000 years and that “the earth needs more CO2 to support life.”

But the carbon in our atmosphere isn’t even close to being at its lowest levels, says James Miller, a researcher on global climate change at Rutgers University–New Brunswick.

“Except for the recent period of increase, CO2 levels have been below 300 ppm for thousands of years,” he writes in an email to Corporate Knights. The atmospheric reading of CO2 reached 420 parts per million last year, according to the World Meteorological Association, which notes in a press release that “the last time the Earth experienced a comparable concentration of CO2 was 3–5 million years ago, when the temperature was 2–3°C warmer and sea level was 10–20 meters higher than now.”

And while increased carbon dioxide can be helpful for plants when everything else is equal, Miller explains, “everything else is not equal, and adding more CO2 leads to increasing temperatures, which can lead to less plant productivity.”

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Davidson calls the argument that more CO2 will be good for plants “absolutely preposterous,” not only because global warming leads to more droughts, but also because crops are temperature-dependent. Above certain thresholds, plant productivity declines precipitously, she says. NASA has predicted that factors including temperature stress from climate change could lead to a 24% decline in global maize crops as soon as 2030, which the study’s author says “could have severe implications worldwide.”

The type of CO2 boosterism expressed in the UCP policy proposal isn’t novel. Climate-denying think tanks like Alberta’s Friends of Science Society have been promoting it for many years. But the inclusion in a formal policy document represents a new development.

Climate denialism has grown significantly more entrenched in Alberta’s UCP party, political commentator David Climenhaga writes in an email to Corporate Knights. “Since Smith became premier, to a significant degree the UCP has become more like a comment thread on social media and less like a conventional political party,” he says.

Climenhaga thinks that the odds the resolution will be adopted are “extremely high, like 100%.” If so, it will create a problem for Smith, who is “heavily invested in carbon capture, both as a subsidy to the fossil fuel extraction industry and as a way to win social licence for more extraction.”

“Carbon capture is a real solution – one of the best we know of,” Smith said in November, adding that “Alberta fully intends to lead the world in this critical field.” Last year, she launched an incentive program to cover some of the capital costs associated with new carbon capture, utilization and storage (CCUS) infrastructure in the province.

But according to Climenhaga, the people behind the policy proposal are “increasingly suspicious of carbon capture, not because they think it’s a boondoggle necessarily, but because they believe, as per the resolution, that CO2 is good.”

Alberta’s self-inflicted economic wounds

Abandoning its net-zero targets would set Alberta on a lonely path, marking it as an outlier in the global economy. “A commitment to net-zero is table stakes, in terms of the bare minimum,” Dyer says.

The policy proposal may be mainly symbolic, but “it’s a symbolism that is damaging to the investment climate in Alberta,” Dyer argues. Calgary and Edmonton are home to many entrepreneurs in the decarbonization space, he says, and policies that discourage investment would be economically harmful.

Even Texas, Alberta’s oil-loving American counterpart, has embraced the renewables boom and rapidly ramped up its solar and wind capacity. Three-tenths of its net electricity in 2023 was generated from renewable sources, according to the U.S. Energy Information Administration.

The proposed measure to abandon its net-zero targets would also put Alberta out of step with its own energy sector. Most oil and gas companies see a need for energy diversification and have made commitments to reduce greenhouse gas emissions. “The industry has been very good cutting back the use of diesel and methane emissions, carbon capture – they’re very active on that side,” says Josef Schachter, president of Schachter Energy Research, in an interview with the CBC.

It was economic factors and not climate change that drove the shift toward renewables in Texas, and the same could theoretically be true in Alberta. Even if the province doubles down on science denial, that doesn’t mean it has to deny cheap renewable power.

Mark Mann is an associate editor at Corporate Knights.

The post Alberta’s conservative party invites climate disinformation into policy debate appeared first on Corporate Knights.

One year after the provincial government imposed a seven-month halt on new solar, wind, hydro, biomass and geothermal ventures, a report from environmental think tank the Pembina Institute reveals that 53 projects were cancelled, representing more than 8,600 megawatts of power-generating capacity. Of those cancellations, 33 projects were already in the development queue at the time of the announcement and could have produced enough energy to power almost all Albertan homes, the study found. An additional 20 projects were part of a flood of developments that surged immediately after the announcement, in the hopes of being grandfathered in under the old rules. That interest has since plummeted, the researchers say.

“It appears that the moratorium created sufficient uncertainty in the renewable energy sector even after it formally ended in February 2024 that new applications have, for now, reached a standstill,” the Pembina report authors note.

The 53 cancelled projects would have drawn in some $91 million in tax revenues. Meanwhile, Alberta cities that already had renewable projects functioning have seen the taxes they collect double over the last year, from $28 million to $54 million, according to Business Renewables Centre-Canada (BRC-Canada), a subsidiary of Pembina. For five communities, these proceeds constitute 20% to 30% of their total annual operating revenues. “This revenue is reliable, stable income that communities can plan around for decades to come,” Jorden Dye, director of BRC-Canada said in a statement.

The Alberta government dismissed the report as one that “intentionally misconstrues the facts.” Nathan Neudorf, Alberta’s minister of affordability and utilities, said, “The Pembina Institute is ignoring the reality that not every proposed energy project leads to shovels in the ground.”

According to the Pembina report, three of the 118 projects that were under development at the time of the moratorium have since been approved and another 20 are “advancing.”

“What we have in truth is a growing queue for energy projects, not a shrinking one,” Neudorf said in a statement to the Canadian Press. “Alberta continues to be a leader in renewable energy and jurisdiction of choice for investors.”

Alberta imposed the moratorium August 3, 2023, officially citing “concerns raised from municipalities and landowners related to responsible land use and the rapid pace of renewables development.” But the unexpected move, in a province where renewables were taking off, reflected an ongoing battle with the federal government over climate policy and energy. At the time, Premier Danielle Smith blamed Ottawa for thwarting the natural gas development that she argued would be needed to keep a renewables grid humming. Experts have said that such a backup is not necessary.

The Alberta government lifted the ban in February of this year and released rules around how renewables could proceed. For example, renewable projects are no longer permitted on Class 1 and 2 agricultural lands unless the project can coexist with farming, and areas designated as “pristine viewscapes” must have a 35-kilometre buffer for new wind projects. However, the Pembina Institute says that the government has yet to provide an official map outlining where new projects might be approved.

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Alberta’s approach contrasts with that of similar jurisdictions such as Ontario, which after cancelling renewable contracts five years ago is once again pursuing wind and solar projects to help bridge its power gap. South of the border, red states have been leading in wind and solar development in the U.S. in recent years, although the upcoming presidential election has thrown new uncertainty into the mix.

The International Energy Agency predicts that more than $2 trillion will be invested in renewables around the world this year.

“The Alberta government’s efforts to stunt the growth of the most promising renewable energy market in the country has been a deeply regrettable success,” noted Stephen Legault, with Environmental Defence, in a statement.

At the same time, Alberta is forecasting continued growth in its oil and gas sector, with higher prices and increased access through the Trans Mountain pipeline system.

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The terms are contained in Bill C-59, which received royal assent last week and includes several changes relevant to companies doing business in Canada. Among them are amendments to the Competition Act that intend to address unsubstantiated environmental claims.

The bill prohibits a public “statement, warranty or guarantee of a product’s benefits for protecting or restoring the environment or mitigating the environmental, social and ecological causes or effects of climate change” if the claims are not based on “an adequate and proper test.” It also demands that the claims be in accordance “with internationally recognized methodology.” In both cases, the onus is on the person making the claims to provide the relevant proof. In addition, consumers will now be able to take their complaints directly to the Competition Tribunal. Those found to be in violation could be slapped with penalties up to $15 million and 3% of a corporation’s annual worldwide gross revenues.

A coalition of environmental and health organizations celebrated the bill, describing it as “a potential watershed moment” in dealing with the “systemic problem” of making spurious environmental claims. “False green claims, or greenwashing, not only deceive consumers but also contribute to pollution and environmental degradation, with serious implications for human health,” said Leah Temper, with the Canadian Association of Physicians for the Environment (CAPE), an organization that has been pushing to ban fossil fuel advertising altogether in Canada. In addition, “it skews the competitive landscape, impairs sustainable consumption decisions, harms consumer trust and undermines companies’ incentives to invest in green innovation,” noted Tanya Jemec, a lawyer at Ecojustice.

While most of the attention has been focused on oil and gas companies, the regulations in Bill C-59 are not specific to any one industry, suggesting that new scrutiny could now be applied to popular terms such as “net-zero,” “carbon-neutral” and “sustainable.”

For the Pathways Alliance, a coalition of six of the largest oil and gas producers in the country – and currently under investigation by the Competition Bureau for its environmental claims – the new rules create “significant uncertainty” for companies trying to communicate how they are trying to improve their environmental performance. As a result, it erased all content from its website, social media and other public communications. Other oil and gas companies have removed information from their websites or added disclaimers.

“This is a direct consequence of the new legislation and is not related to our belief in the truth and accuracy of our environmental communications,” Pathways Alliance said on its website.

The province of Alberta also chimed in with outrage, issuing a statement calling the legislation “absurd authoritarian censorship” that will serve only “to stifle the many billions in investments in emissions reducing technologies” and block the ability of Canadians to “hear the truth about the energy industry.” It said it was considering mounting a constitutional challenge or the use of the Alberta Sovereignty within a United Canada Act to “protect free speech.” In the days leading up to the bill’s royal assent, the province shut down its controversial Canadian Energy Centre, also known as its “energy war room,” a publicly-funded provincial corporation that had been created to defend the energy sector.

Law firms such as BD&P raised concerns about “the uncertainty and ambiguity” of the wording in the bill, but some advocates point to the fact that details will be fleshed out in guidance expected to be issued by the Competition Bureau to help companies know when they’re crossing a line. Environmental organizations say the legislation itself is already proving effective.

“The fact that Pathways Alliance has taken such drastic action shows that they know they don’t have evidence to support the story they’re selling on carbon capture, and that its member companies’ business plans don’t align with a net-zero future,” Emilia Belliveau, energy transition program manager for Environmental Defence, said in a statement.

The Pathways Alliance is behind a massive venture to build a carbon capture and storage (CCS) project that it says would help its member companies cut greenhouse gas emissions by 32% from 2019 levels by 2030 – an unproven technology that climate advocates say will simply give Canadian fossil fuel companies licence to keep drilling. The project involves building a 400-kilometre pipeline that would transport carbon dioxide from oil-sands facilities in northern Alberta to an underground storage chamber. A recent report from U.K. think tank InfluenceMap notes how, through Pathways, companies are branding themselves as “climate conscious entities” that publicly promote technologies like carbon capture storage “as a cover to weaken and block climate policy.”

InfluenceMap research shows that while Pathways presents “optimistic messaging” related to CCS publicly, correspondence with policy-makers suggests “a notable lack of confidence in CCS technology to achieve climate goals.” The Pathways Alliance is already under investigation by the Competition Bureau for its “Let’s clear the air” advertising campaign, which Greenpeace has alleged makes false and misleading claims about reducing emissions and helping Canada achieve its climate targets.

Ecojustice, CAPE, Équiterre, and the Quebec Environmental Law Centre called on François-Philippe Champagne, the federal minister of innovation, science and industry, to explicitly prohibit vague and hard-to-prove terms such as “green,” “eco-friendly” and “climate-neutral” through new regulations under the Competition Act. And they urged the Competition Bureau to hold public consultations before releasing finalized guidelines that will identify the standards that businesses are expected to meet. The European Union, for example, prohibits generic environmental terms such as “eco-friendly” and “biodegradable” and insists companies include clear specifications in prominent language on the same packaging, label or website.

“While the passage of Bill C-59 is a significant step towards clamping down on rampant greenwashing in Canada, gaps remain that will make it challenging to hold companies to account,” said Jemec, with Ecojustice, in a statement. That includes the kind of proof that companies will have to give to the public about their claims. While the Competition Tribunal might compel companies subject to complaints to provide this information during litigation, it might not be disclosed publicly, Jemec said

“And more importantly, what is still missing is transparency outside of litigation in the places where consumers are being bombarded with green claims,” she says. “This means that consumers – as well as competitors and regulators – are unable to easily verify the credibility of a company’s green claims at the time that they have to make decisions based on those claims, e.g. the point of purchase.”

France requires companies making environmental claims to disclose information about their claims in a format that is easily accessible at the time of purchase, for example with a QR code.

“Businesses that want the benefits of making a green claim should be willing and able to provide supporting information to the public upfront,” she said, “not just when challenged.”

The post Canada’s new greenwashing ban rattles fossil fuel industry appeared first on Corporate Knights.

This policy flip-flop, mixed with poor government communication and sustained attacks by politicians that prey on affordability concerns, isn’t advancing Canada’s economic or environmental objectives. Never mind the generous rebate cheques distributed by the federal government, leaving most families better off, or the drag on national prosperity from the wilder weather and extreme storms that heat-trapping pollution brings. This ongoing debate is a dangerous distraction from the hard task of building effective, efficient climate policy.

But the carbon tax is not the whole carbon-pricing story in the country. Behind the scenes, industrial carbon pricing through large-emitter trading systems (LETS), including output-based pricing or cap-and-trading systems, is propelling Canada’s clean energy transition. A new report by the Canadian Climate Institute shows that this industrial price on carbon will be roughly three times more effective at cutting emissions between now and 2030 than the carbon tax – contributing a whopping 53 to 90 megatonnes of reductions towards the 2030 target.  And even in Alberta, industrial carbon pricing is alive and well – and bringing down emissions.

Since 2007, successive provincial governments in Alberta have updated their industrial carbon-pricing program targeting large emitters, including producers of oil and gas, chemicals and cement. And the basic design of Alberta’s system has been adopted across the country. Currently, 42% of national emissions are covered by federal, provincial and territorial LETS, with tradable emissions credits valued at $2.4 billion and rising with the national carbon price. By comparison, the federal fuel charge covers 34% of national emissions.

Despite the rhetoric against carbon pricing, governments of all political stripes have become comfortable making big polluters pay. But why? The answer is simple: LETS are good at reducing emissions, good for business and good for competitiveness. To remain effective, however, adjustments will need to be made.

Let’s look closer at what LETS have going for them.

LETS protect competitiveness by lowering costs

To keep balance-sheet costs manageable, the carbon price is applied to only a fraction of industrial emissions, with typically 75% to 90% of emissions unpriced. The incentive to reduce emissions, however, remains unchanged since every emission reduced is still valued at the full carbon price. With the carbon price rising to $170 by 2030, every tonne reduced is worth $170, while the compliance cost that firms face in that year ranges between $17 and $43 per tonne of emissions (assuming unpriced emissions are still 75% to 90%). This means that a chemical plant with 100,000 tonnes of emissions would see carbon costs somewhere between $1.7 and $4.25 million instead of $17 million if all emissions were priced.

As competitiveness risks change, regulators can change the quantity of unpriced emissions. They do this through revaluating the level of the performance standard, which sets the level of unpriced emissions, typically expressed as emissions per unit of production (i.e., allowable emissions per tonne of steel produced). Should competitiveness pressures worsen, the level of unpriced emissions can be increased, and vice versa. To assess competitiveness pressures, Alberta has a series of profit and sales tests that determine whether the financial impact of compliance on a facility is significant. These tests compare the costs of carbon pricing to firm profit or sales. If a threshold is exceeded, the quantity of unpriced emissions is increased, thereby lowering costs.

This scalability to changing competitiveness – or even technology conditions should abatement become easier due to innovation – makes LETS a flexible policy option.

LETS provide a revenue stream for low-carbon projects

Companies are able to sell credits when they reduce emissions and outperform their performance standard. And with carbon prices rising, emission credits will gain value. As this happens, firms can decide whether to sell credits at a profit or bank them to potentially apply them against rising future carbon-pricing costs. This profit motivation becomes particularly strong when assessing whether to invest in emissions-reduction technology, such as carbon capture, utilization and storage.

LETS protect against border carbon tariffs

LETS also help smooth protectionist waters as countries implement carbon border tariffs. With LETS in place, the risk that other countries will impose carbon tariffs on Canadian exports lowers. The protectionist winds are blowing hard out of Europe, where the European Union will apply a carbon price on imports from specific industries, including cement and steel. Various carbon protectionist tariffs are also being contemplated in the United States that would first assess the emission intensity of key products, including aluminum, cement, oil, fertilizer, iron and steel. The Unites States then would seek to apply a border carbon charge or tariff on carbon-intensive imports, increasing the market price in the United States for Canadian products.

Let’s get the details right

There are two big risks that need to be addressed to ensure that LETS can continue to contribute emission reductions in line with Canada’s climate targets. First, recent analysis by the Canadian Climate Institute indicates future LETS market prices don’t always hold at the national carbon price, notably in Alberta, due to an oversupply of credits.  Credit oversupply can happen for a variety of reasons, including when firms are granted more credits than needed for compliance; technology investments, spurred by subsidies, generate large volumes of credits; and overlapping policies double count reductions. The institute’s analysis shows that addressing credit oversupply and some policy overlap, notably between LETS and the oil and gas emissions cap, can cut another 15 megatonnes of national emissions by 2030 from industrial processes. This 15 megatonnes equals more than a third of the reductions needed to close Canada’s 2030 emissions gap.

This policy fix is straightforward. Regulators need to routinely monitor and update greenhouse gas performance standards to make them stricter. The movement toward government insuring against uncertain future carbon prices, as in the case of carbon contracts for differences and credit offtake agreements, can also help maintain investment certainty.

Second, market transactions and trading prices are opaque and apart from Quebec’s cap-and-trade system, there is no foresight on the current or future value of emission credits in the LETS markets. This adds uncertainty for investors but also limits the ability for regulators to predict market imbalances and take corrective action. Canadian LETS markets are currently worth about $2.4 billion, but this value rises rapidly with the carbon price and stricter performance standards, growing to $6 to $7 billion by 2030. It’s astounding that market oversight and trading systems are not yet in place to track how these markets function and whether the market price holds.

It is no wonder that LETS are the policy tool of choice across Canada and across the political spectrum. These systems incentivize emission reductions, minimize competitiveness risks, and calm the threat of border tariffs on Canada’s exports.

LETS get the job done.

Dave Sawyer is principal economist with the Canadian Climate Institute and operates EnviroEconomics.

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