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.

The post Canada’s oil patch has a data problem and it’s putting public health at risk appeared first on Corporate Knights.

Oil prices shot up on Monday as disruptions related to the war in Iran sent shockwaves through financial markets, underscoring the risks for countries that have been slow to diversify beyond fossil fuels.

Brent crude oil, the benchmark for a majority of the world, surged to nearly US$120 per barrel, the highest it had been since 2022, when Russia invaded Ukraine. Prices for West Texas Intermediate crude oil, the U.S. benchmark, rose to about $100, also the highest since 2022.

As Iran has faced attacks from the United States and Israel, it has responded in part by threatening oil tankers travelling through the Strait of Hormuz. Some producers have reduced or paused their output in response to this risk, according to the International Energy Agency.

“This shock is being driven by geopolitics and physical supply risk, so prices are moving quickly through global markets,” says Jan Rosenow, professor of energy and climate policy at the University of Oxford, in an email. “That makes it feel sudden and hard to control.” Countries with more renewables in their power mix are less exposed to the price spikes, which reduces the inflation they will see compared with past oil crises, he says.

Gernot Wagner, an economist at Columbia Business School, says the price spike provides a familiar warning for policymakers. “The biggest lesson: Oil – much like coal and gas – is a commodity. Its price will always fluctuate based on geopolitical whims,” he said in an email. “Solar, batteries, heat pumps, induction stoves are technologies. They can only get better and cheaper over time.”

President Donald Trump acknowledged high oil prices on Sunday, posting the following on Truth Social: “Short term oil prices, which will drop rapidly when the destruction of the Iran nuclear threat is over, is a very small price to pay for U.S.A., and World, Safety and Peace. ONLY FOOLS WOULD THINK DIFFERENTLY! President DJT.”

The U.S. average price for regular gasoline is $3.48 today, according to AAA, an increase from $3 a week ago.

U.S. Energy Secretary Chris Wright said Sunday during a CNN interview that tanker traffic will soon resume on the Strait of Hormuz. Asked about rising gasoline prices, he said the increase many consumers saw over the weekend is likely to be short-lived. “We want it back below $3 per gallon, and it will be again before too long,” he said. Wright said this will take “weeks” and is not a “months thing.”

Some observers have drawn parallels between the current price shock and the one that followed the 1979 Iranian revolution. But Rosenow notes some big differences: “The key difference from the 1970s is that we now have credible alternatives.” He adds, “Each price shock reinforces the same lesson: energy security and climate strategy are aligned. Cutting dependence on imported fossil fuels is not only about emissions; it is about reducing structural economic risk.”

Dan Gearino covers the business and policy of renewable energy and utilities, often with an emphasis on the midwestern United States. 

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Scarcely a week passes without another handout to add to the pile.

Most of this work has involved undermining anything that promotes renewables and electric vehicles or puts regulatory constraints on large emitters. But the Trump regime has also surreptitiously opened up a somewhat unexpected front in its denialist war: the International Energy Agency’s annual modelling exercise, widely seen as the definitive prognosis for long-term power demand and its impact on the earth’s climate.

Recognizing that forward-looking scenarios help shape the futures they describe, fossil fuel lobbyists and their allies in government mounted a back-channel pressure campaign. They threatened to withhold the United States’ 14% contribution to the IEA’s budget unless the multi-lateral agency stopped talking about third-rail topics like peak oil and instead put out forecasts that muddied the energy transition waters. Their primary target: restoring the IEA’s reliance on an innocuously named energy model, known simply as the “current policies scenario” (CPS), which the Paris-based organization dropped back in 2021, at a radically different political moment.

Guerrilla warfare

When the IEA released its World Energy Outlook (WEO) in October 2021, the agency sketched out two versions of the future: the “stated policies scenario” (STEPS) and the more ambitious “announced pledges scenario.” Together, they provide a view of what 2050 would look like, either with modest progress or bolder ambition, respectively.

Yet in a move that channelled the spirit of that fleeting moment, the IEA added something new and exciting: the “net-zero emissions by 2050 scenario.” This model, it stated, “charts a narrow but achievable roadmap to a 1.5 °C stabilisation in rising global temperatures and the achievement of other energy-related sustainable development goals.” Climate advocates were thrilled by both the IEA’s big goal and its instructions for how to get there. Meanwhile, the Organization of the Petroleum Exporting Countries and U.S. oil and gas interests fumed about all these models forecasting their demise.

It took five years for the backlash to reach IEA’s analysts. For the 2025 edition of the WEO, released in November, the agency’s most ambitious scenario is now STEPS, which scoped out the least aggressive energy transition in 2021. The CPS scenario – which anticipates a catastrophic 3°C increase in global warming by 2050 – was back, while net-zero by 2050 had vanished without a trace. The NZE remains, for now, but Neil Grant, senior climate policy analyst at Climate Analytics, worries about whether it will be excised next year. “If the IEA caves there and gets rid of it, I think you will start seeing people saying, ‘what’s the point?’”

In a lengthy blog post accompanying the new WEO, two senior IEA officials explained the differences between STEPS and CPS with the example of vehicle efficiency standards in Japan. “Under CPS, these policies continue after their end-date but are assumed not to be strengthened,” they wrote. “The STEPS assumes they continue and are strengthened in line with the previous ambition.” The current Japanese policy aims to improve vehicle efficiency by 20% by 2030. Both scenarios reflect the bump, but STEPS predicts that efficiency will continue improving after 2030, while CPS doesn’t assume any more momentum.

“None of the scenarios in the WEO are a forecast,” the authors wrote in a commentary outlining their methods. Nor did the IEA’s use of CPS indicate the presence of a finger on the scale. The IEA’s aim, they said, is to rationally explore the consequences of different policy choices.

It’s clear that there’s been quite a lot of pressure this year in terms of their funding.

— Guy Prince, head of energy supply for Carbon Tracker

But critics didn’t buy the IEA’s wonky explanations about the renewal of empirical rigour, pointing out that CPS ignores the inevitability of continuing technological innovation, takes uninterrupted growth in oil and gas demand as a given, and foresees no drop in emissions. “What the CPS does is take that Trump administration worldview that we’re seeing implemented the U.S. and assumes its dominance across a whole range of other sectors and across the rest of the world,” adds Grant.

In effect, the CPS provides a road map to 2050, but with 2024 policies frozen in place. IEA watchers claimed that its presence is meant to deliver cover to the fossil fuel backers in and around Trump and MAGA congressional Republicans. Indeed, on the eve of the new WEO’s release, which coincided with COP30 in Brazil, a pair of senior congressional Republicans rewarded the embattled agency with a bit of mobbish praise. In a letter, they congratulated IEA executive director Fatih Birol for freeing the agency from the evils of “activism”: “This course correction, which U.S. House Committee on Energy & Commerce leadership has been requesting, will help restore the IEA’s credibility and impartiality.”

“It’s clear that there’s been quite a lot of pressure this year in terms of their funding,” says Guy Prince, head of energy supply for Carbon Tracker. He describes the return of CPS as “a subtle re-positioning” with enormous consequences.

Dave Jones, chief analyst at U.K.-based Ember Energy Research, says that by restoring CPS and situating it as the counterpart to STEPS, the energy agency is signalling a problematic equivalence to global policymakers and investors. “The biggest issue I have with it is that the IEA have used it as equal weighting to the STEPS scenario,” he observes. “I don’t think people expected that to happen.” Most analysts, policy experts and investors would have expected to see CPS offered as a secondary scenario, he says.

The realpolitik here is about buttressing the oil and gas industry’s ability to raise capital and continue operations in the face of an increasingly efficient and inexpensive clean-electricity industry dominated by China, explains Keith Stewart, Greenpeace Canada’s energy analyst. “Adding this scenario is part of that guerrilla warfare going on to try and support an oil and gas industry that is fighting for its life,” he says. “They’re not going to disappear tomorrow, but they can see the writing on the wall unless they can somehow get enough political muscle behind them to stop the transition.” (The Canadian Association of Petroleum Producers did not respond to a request for an interview.)

Slow-walking the energy transition

Trump’s targeted attack on the IEA’s long-range models operate in lockstep with his administration’s shocking assault on science. Since January, a series of moves across the U.S. government have hobbled environmental policy by choking off climate data and cancelling climate science. Agencies that gather and analyze empirical information – the Environmental Protection Agency, the National Oceanic and Atmospheric Administration (NOAA), the Department of Energy, as well as countless university scholars – have had their research budgets slashed, their websites raided and their data streams blocked.

A major concern is access, says Mark Winfield, a professor of environmental studies at York University. “If you were doing observational atmospheric science, for example, are you going to lose data from NOAA satellites and the kind of thing that they use on an ongoing basis? That applies to things like the Intergovernmental Panel on Climate Change, because U.S. science and data underlies an awful lot of that work.”

In the case of the IEA’s models, scenarios aren’t climate science, per se, but they involve complex economics, deep policy research and assumptions about how all sorts of industries will evolve over coming decades; the IEA even publishes a 143-page technical document showing how it builds its scenarios. Like so many other forms of climate data, these models become critical decision-making tools for government officials, investors and other stakeholders, including the fossil fuel industry itself. “They have significant weight,” says Grant. “They’re used a lot in the investment community to decide where we should be putting capital.”

The Trump administration is trying to pull every lever it can to help support its own narrative.

— Dave Jones, chief analyst at Ember Energy Research

Greenpeace’s Stewart points to the various scenarios developed by Suncor for investors back when it was more rhetorically engaged in energy transition debates. The energy giant’s 2022 ESG report talked about how it would adjust its capital investments based on high- or low-demand oil scenarios. “There was a section on how Suncor should change its business model depending on which scenario,” he says, noting that the company walked investors through both high- and low-carbon outlooks, as well as a business-as-usual version, to show their thinking about asset allocation. (Suncor didn’t respond to requests for an interview.)

The IEA’s use of the CPS assumes sluggish innovation in the clean-energy world, but all evidence points to the contrary. “CPS doesn’t reflect the reality of what is happening in terms of new technological deployment,” says Prince at Carbon Tracker. It’s a bit like someone in the 1950s imagining a long-range air pollution forecast that anticipates that leaded gasoline would always be the default vehicle fuel and that nothing like the 1963 Clean Air Act would ever become law. Indeed, CPS isn’t even a business-as-usual scenario; it’s more of a long look in the rear-view mirror at a world that is fast receding into the distance.

The IEA, which stresses that its scenarios aren’t forecasts, defends the reintroduction of the current policies scenario by arguing that as-yet-unforeseen constraints might drag on the current dynamic of change, such as “insufficient infrastructure, grid integration costs, a lack of institutional capacity or financing, or the absence of continued policy support.” As a result, its authors acknowledge, it projects a slower adoption of new technologies than recently seen.

The problem, as history has repeatedly shown, is that neither technological innovation nor economies of scale run in reverse, so CPS doesn’t even function as a bracing worst-case scenario. Stewart points out that Chinese-made solar panels now produce the cheapest energy on the planet, with extraordinary deployment rates, especially in Asia. (China is building an eight-gigawatt solar farm in inner Mongolia that will be 30 square kilometres larger than New York City.) Trump strong-armed constraints on U.S. renewables producers, even as the rest of the world’s nations beat a path to China’s doorstep to place their own mass orders for inexpensive panels and EVs. Such is economics: the evidence suggests that demand for renewables is growing, not slipping.

The bottom line is that the CPS may become the oil and gas sector’s aspirational anchor, a plausible version of the future that it can tout to fossil fuel investors. But the industry will eventually have to confront the implacable fact that it no longer produces a cost-competitive product, much less an environmentally friendly one – regardless of what the IEA’s dubious model envisions.

Jones at Ember Energy Research takes the wide view. The IEA’s decision to bring back CPS, he says, feeds into a broader push to put fossil fuels back to a place of energy primacy – a place the industry feared it had surrendered during the peak oil days. It’s about storytelling, not what’s actually going to happen, Jones observes. “The evidence is the Trump administration is trying to pull every lever it can to help support its own narrative.”

Like so many global institutions that have found themselves under siege from this president, the IEA may find its reputation as an honest information broker broken, which is a scenario no one wants to see.

John Lorinc is a journalist and author specializing in urban issues, business and culture.

The post Is the International Energy Agency bending to Big Oil? appeared first on Corporate Knights.

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.

On Wednesday, Trump’s Department of Energy put out a “fact sheet” stipulating that the United States is “selectively rolling back sanctions to enable the transport and sale of Venezuelan crude and oil products to global markets.” This outcome is doubly ironic because U.S. sanctions are one of the reasons the Venezuelan oil industry is diminished in the first place. The announcement also states that the United States will market Venezuelan oil, bank the proceeds and disburse the revenue “for the benefit of the American people and the Venezuelan people at the discretion of the U.S. government.”

Maduro first drew the ire of President Trump in 2017 after the Venezuelan government stripped powers from the opposition-controlled legislature and violently suppressed mass protests. Trump responded by imposing sanctions on Maduro, several senior officials and Venezuela’s state-owned oil company, significantly broadening the targeted sanctions that the Obama administration first imposed in 2015. Speaking to reporters at his golf club in Bedminster, New Jersey, that August, Trump said he would not rule out a “military option” in Venezuela.

Two years later, after Maduro secured a second term in a contested election, the Trump administration dramatically escalated its pressure campaign, announcing a full oil embargo on the country. Venezuela holds the world’s largest proven oil reserves and produces a kind of heavy crude used to make diesel fuel and petrochemicals. At the time, the United States received roughly 40% of Venezuelan oil exports. The embargo severed not only that trade but also exports to European Union countries, India and other U.S. allies. Suddenly, Venezuela was largely cut off from global markets.

By the time sanctions kicked in, Venezuela’s oil production was already slipping. Low oil prices in the early 2010s caused instability for an industry that had long been plagued by mismanagement, corruption and underinvestment. But the sanctions delivered a devastating blow.

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It’s the 10th anniversary of the Paris Agreement, that lofty climate pledge that has helped push – in some cases reluctantly – countries toward carbon-cutting measures. COP30 organizers are determined to make this year different, shifting from “ambition to implementation,” and they’re making the point with a backdrop of stark inequality.  

“We cannot hide the fact that we are in a world with lots of inequalities and where sustainability and fighting climate change is something that has to get closer to people,” André Aranha Corrêa do Lago, president designate for COP30, said in an interview with the Associated Press. “President Lula wants this to be the COP of truth. He wants people to be told the truth about how climate change will affect their countries,” he added in September.  

Brazil proved to be its own study in contradictions in the lead-up to Belém, which has made headlines for a dearth in accommodations for the influx of thousands of delegates, as well as a controversial new highway cutting through rainforest to facilitate the conference. South America’s largest country, with a population of more than 212 million, Brazil has sought to regain environmental bona fides that were left in tatters under the previous administration of Jair Bolsonaro, when deforestation ran rampant in the Amazon.  

Luiz Inácio “Lula” da Silva, former union leader turned president, assumed his third term in office in 2023 with bold pledges to end deforestation in the Amazon by 2030, boosting the use of satellite monitoring and other mechanisms to guard against illegal logging and mining in the so-called lungs of the earth. He also established a dedicated ministry for Indigenous Peoples as a way to protect their rights, setting out to demarcate their territories. In the lead-up to COP30, Brazil launched a tropical-forest conservation fund that aims to raise US$125 billion. Hosting COP30 was an important show of his government’s environmental commitment. Brazil has pledged to reduce its emissions by 59% and 67% below 2005 levels by 2035. But various activists and organizations have drawn attention to the cracks in Brazil’s narrative, not least for its plan to continue to exploit its oil reserves.  

Lula has pushed for Brazil to drill in the mouth of the Amazon, arguing that the development will help the country complete its energy transition. The Brazilian Institute of Environment and Renewable Natural Resources approved the drilling of an exploratory well in an offshore oil field in the Amazon, a site that had long been in the sights of the national oil company, Petrobras. The petroleum giant had previously been denied rights to explore, in large measure because of doubts over its ability to respond to oil spills or other accidents in the ecologically sensitive area. In its October approval, the environmental watchdog said the company had made various improvements to its emergency response plan, which led to the green light. 

Brazil is also pushing ahead with new mining projects for critical minerals, with as many as 800 mining companies exploring in the Amazon. “There is no energy transition without mining,” Alexandre Silveira, minister of mines and energy, said in early 2024. 

“Brazil cannot lead the world to a cleaner, healthier future by loosening environmental regulations, promoting a fossil fuel build out, and allowing mining projects that violate Indigenous sovereignty and destroy carbon sinks like the Amazon,” Patricia Rodriguez and Jan Morrill wrote in a commentary for Earthworks, an organization that advocates against oil, gas and mining pollution.   

The question of environmental regulations has exposed fault lines within Lula’s administration. Environment and Climate Change Minister Marina Silva, an internationally acclaimed environmentalist, slammed a decision by the Brazilian Senate in May to approve a bill that loosened environmental licensing rules, calling it a “death blow” to important protections in Brazil. Her position in turn drew the ire of industry and other sectors. The legislation was later modified, earning Silva’s support. 

But the showdown underscored the powerful forces that are at play in Brazil, which has taken an even more prominent role on the international stage as President Lula presents one of the clearest voices of opposition to U.S. President Donald Trump and his trade war tactics.  

In opening remarks at COP30 last week, Lula stressed the need for true climate commitments, to “take the scientific warnings seriously” and “face reality.” He closed by thanking people for coming to the Amazon.

“Many people did not believe that it was possible to bring a COP to an Amazonian state, because people are more used to parading around big cities,” he noted. “We wanted people to come here to see what the Amazon really is.”

The post Brazil’s balancing act at COP30 appeared first on Corporate Knights.

The Phillips 66 refinery south of Los Angeles is slated to close by the end of this year, an announcement the company made last fall, two days after Governor Gavin Newsom signed legislation giving the state more authority to regulate such operations. This spring, Valero said it will close its Bay Area facility in 2026, citing in part a record US$82-million fine for air pollution that was more than 360 times the legal limit.

Valero did not respond to a request for comment. Phillips 66 spokesperson Al Ortiz told Grist, “Our focus right now is on safely idling our facilities. We are proud of the work we have done and continue to do with the state to ensure we will be able to meet future market demand.”

Between the two closures, California is slated to lose 17% of its refining capacity, which could cause gas prices to surge past the already nation-leading price of US$4.50 per gallon. It’s unclear what the closures might mean for reducing greenhouse gas emissions, as the state will likely import gasoline to cover a portion of the shortfall and people tend not to drastically decrease consumption even when prices go up.

Lawmakers don’t appear to have planned for this scenario. “The state is largely without a system-wide transition plan,” Cottie Petrie-Norris, a Democrat who represents portions of Orange County in the state assembly, said at a recent hearing. Creating such a road map, she noted, “is one of the most complicated, and I believe important, challenges that policymakers will need to face in the decade ahead.”

Without a plan in place, environmental advocates worry that the state will shove aside its progress combating climate change to keep gasoline flowing. California has for years led the nation in adopting stringent fuel-economy standards, setting aggressive greenhouse-gas-reduction targets and enforcing strict environmental regulations. But, in their attempts to keep the refineries online, even Democrats are proposing measures such as fast-tracking drilling permits and pausing a profit cap on refineries, a step the state took in 2023 to control gas prices and combat price gouging.

“What we’re seeing right now from lawmakers in California is an attempt to appease Big Oil,” says Faraz Rizvi, policy and campaign manager at the Asian Pacific Environmental Network, an environmental justice organization. “The crisis of affordability in California and the results of the last election have really shaken California Democrats, and they are really embracing a drill-baby-drill approach.”

Rizvi points out that while oil companies have done a good job pinning blame for the closures on California regulations, market forces were already pushing in that direction. The consultancy Wood Mackenzie estimates that nearly a quarter of all oil refineries worldwide are set to go dormant by 2035. One recently began shutting down in Texas, which is among the most favourable business environments for fossil fuel companies. In California, survey data shows that demand for gasoline has dropped by roughly 15% since 2017. Ortiz nods toward those trends when he tells Grist in an email, “Phillips 66 announced the idling of its Los Angeles-area refinery as part of its focus on the long-term value of its asset portfolio.”

Rizvi is much more direct. “This is all about their profit margin. Their bottom line,” he says of oil companies, which have seen record profits in recent years. “They had the opportunity to hold California consumers hostage and they took it.”

Proponents of a fuel-agnostic free market disagree, saying that policymakers’ attempts to pressure oil and gas companies amounted to the state putting its thumb on the scale and contributed to the current crunch. “All of these politically creative costs make it more and more difficult to operate,” says Wayne Winegarden, who oversees environmental work at the libertarian Pacific Research Institute. “We as Californians have gone a little bit too far by not accounting for the costs we’re imposing by accelerating a transition that it is clear we’re not ready for,” he says. “We put ourselves in this very difficult situation.”

Despite a split on why the refineries decided to shut down, all sides generally agree that the state wasn’t ready for the moves. Rizvi says that this “middle” phase of an energy transition can be especially difficult to navigate as older technologies sunset and newer ones come on line. “California should have recognized that we are in a perilous moment,” he says.

While California leads the country in electric vehicle adoption, such cars still account for less than a quarter of all vehicles sold statewide. Federal EV tax credits are set to end this fall, and President Donald Trump’s administration has tried to freeze funding for charging station infrastructure (though recently reopened it). “You’re trying to force people into using technology that isn’t ready to take on that burden,” Winegarden says.

Exactly how California gets out of this conundrum is up for debate. Winegarden says that it’s important to be open to the role that all fuels, including oil, can play in the state’s energy future. Rizvi sees this as an opportunity to bolster investments in alternatives to fossil fuels and commit to a green transition.

Regardless, they say, lawmakers need to chart a course – and quickly. “A piecemeal approach to the transition is not the answer,” Petrie-Norris said at the hearing. “We need a real plan.”

This article originally appeared in Grist. It has been edited to conform with Corporate Knights style. Grist is a non-profit, independent media organization dedicated to telling stories of climate solutions and a just future. 

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Billions of taxpayer dollars once intended to help fight climate change by subsidizing capture and storage of carbon dioxide may instead go to fossil fuel companies to help boost production of oil – one of the main drivers of climate change.

In a February 19 call with investors, Vicki Hollub, chief executive officer of Occidental Petroleum, said she’s had several conversations with President Donald Trump, arguing the “business case” for federal support for carbon capture. “We believe the next round of technology that’s going to add significant barrels . . . will be production that comes from the use of CO2 in enhanced oil recovery,” Hollub said. “And that 50 billion to 70 billion barrels would extend our energy independence by more than 10 years. It’s critically important.”

The United States produced about five billion barrels of oil in 2023. Hollub calls carbon capture a way to keep the oil industry alive amid the international calls to reduce reliance on fossil fuels.

What is enhanced oil recovery?

In enhanced oil recovery, pressurized carbon dioxide is used to force oil out of aging wells. The process is used to produce about 2% of the nation’s oil. Hollub said the industry is turning to carbon captured from industrial sources as the supply of naturally occurring carbon dioxide has dwindled.

Depending on conditions, producing oil using captured carbon can offset the climate impacts of a barrel of oil, making it less carbon intensive. But because new oil supplies lower the market price of oil, it could increase demand for oil, raising overall carbon emissions, according to one analysis by the Clean Air Task Force, which supports carbon capture.

Charles Harvey, professor of civil and environmental engineering at the Massachusetts Institute of Technology, told Floodlight that the net climate impact of using captured carbon for enhanced oil recovery “gets super complicated.”

The pivot from carbon capture as a climate solution to a boost for oil comes as the Trump administration seeks to cut or kill climate-related spending, including billions set aside for carbon capture and sequestration, while also ordering the federal government to pave the way for more fossil fuel production.

A ‘perverse incentive’ for oil companies

Support of carbon capture, though, might alienate a key Trump ally.

The Heritage Foundation and its Project 2025 – which is serving as a blueprint for Trump’s second term – argue that federal incentives for carbon capture should be scrapped. “Most carbon capture technology remains economically unviable, although private-sector innovations are on the horizon,” according to Project 2025. “[Carbon capture utilization and sequestration] programs should be left to the private sector to develop.”

Critics also question the safety of the technology, noting that leaks from pipelines have sent dozens of people to the hospital and forced evacuation orders.

During the Biden administration, Congress allocated about US$8.2 billion to carbon capture projects and increased a tax credit for carbon capture that the U.S. Treasury has estimated will cost $30 billion through 2032.

If Trump allows the carbon capture incentives to stay in place, oil companies could increase production at a time when the international consensus is that no new oil should be produced if the world is to keep climate change in check.

The subsidies “create a perverse incentive, because for companies to qualify for the subsidies, carbon dioxide must be produced, then captured and buried,” Harvey and Kurt House wrote in an opinion piece in The New York Times. The two co-founded the first privately funded carbon capture company in the early 2000s. They left the company when it began selling carbon for enhanced oil recovery.

Occidental has invested heavily in carbon capture, including buying a carbon technology firm for US$1 billion in 2023. The multinational oil company, which bills itself as an industry leader in seeking low-carbon solutions, also is developing a federally supported facility in Texas that would capture carbon directly from the atmosphere, a process called direct air capture.

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While most carbon capture projects are designed to take carbon from a facility’s emissions – such as from a power or chemical plant – direct air capture filters and captures 0.4% of carbon dioxide directly from the ambient air. If Trump allows federal support for the project to continue, Occidental subsidiary 1PointFive stands to receive at least $500 million from the Department of Energy.

‘The last best hope of the fossil fuel industry’

Compared with other funding approved under the Inflation Reduction Act targeted by Trump, such as for solar energy and offshore wind, carbon capture “is in a good place relative to some of the other clean energy tax credits,” said Jessie Stolark, executive director of the Carbon Capture Coalition. “And I would say we’re cautiously optimistic as far as our positioning,” she said. “But, you know, it’s just kind of a moving target at this point.”

Before the incentives, companies had no way to make money from capturing carbon other than to sell it to oil companies for enhanced oil recovery. But since carbon capture incentives were boosted under Biden, more than 270 carbon capture and storage projects have been announced.

Some projects are in limbo as they await direction from the federal government, Stolark said. “There’s more uncertainties, certainly for folks who have federal grants awarded or under contract, given the federal funding freeze, and the different memos and directives that have come out.” 

Stolark’s group and more than 160 other companies and organizations signed a letter to congressional leadership after Trump’s inauguration, urging the lawmakers to maintain support for carbon capture.

One bill introduced this year in Congress would give companies that use captured carbon to recover oil the same amount of tax credit as they receive to permanently store it underground – eliminating the incentive to do so.

Carbon capture incentives are “another subsidy for oil,” said Carolyn Raffensperger, executive director of the non-profit Science and Environmental Health Network, which produced a report last year on the “false promises” of using captured carbon dioxide to produce oil.

The report concludes that using carbon dioxide for enhanced oil recovery is “the last best hope for the fossil fuel industry to keep pumping oil out of the ground. It must end.”

This article was originally published by Floodlight, a non-profit newsroom that investigates the powerful interests stalling climate action. It has been edited to conform with Corporate Knights style.

Pam Radtke is an environment, energy and climate reporter. A long-time New Orleans resident, Radtke was part of the Times-Picayune team that published after Hurricane Katrina.

The post The oil industry is selling carbon capture as a way to boost production appeared first on Corporate Knights.

In advance of this year’s COP28 climate summit, the United Nations Environment Programme (UNEP) says that a steady phase-out of coal, oil and natural gas production is critical to put the world on a path to limit the increase in average global temperatures to 1.5 or even 2°C. 

The fourth annual Production Gap Report, released November 3, adds fuel to the heated debate in Canada surrounding the medium-term viability of the oil and gas industry’s plans to boost production and exports.  

At its release, UNEP and its partners in non-governmental organizations urged governments at COP28 to endorse a negotiated phase-out of fossil fuels. The phase-down should begin immediately, proceed urgently and be completed in the second half of this century, they said. Previous COPs have failed to address the production of fossil fuels. 

Canada isn’t alone in its climate contradiction.  

The 2023 Production Gap Report, released by UNEP, the Stockholm Environment Institute and other partners, found that 19 leading energy-producing countries are planning to extract twice as much fossil fuel supply in 2030 as the maximum that can be burned to keep the world on a 1.5°C track. Their production plans for 2030 would result in 70% more fossil fuel than the maximum limit for a 2°C pathway, the report says. 

Canada’s expectation with regards to higher production and exports of oil and gas to 2030 would put Canada in the top five countries in terms of increases over the next six years. And based on current emission– intensity levels, such fossil fuel production would be wholly inconsistent with Canada’s pledge to reduce overall emissions by 40 to 45% by 2030 and become a net-zero emitter by 2050, the UNEP report notes. 

At the global rate of fossil-fuel production and consumption, the buildup of greenhouse gases in the atmosphere will wreak havoc on weather patterns and bring killer heat waves and droughts, severe flooding from rising sea levels and extreme rainfall, and rapid biodiversity loss. 

“The addiction to fossil fuels still has its claws deep in many nations,” UNEP’s executive director, Inger Andersen, writes in the forward to the report.  

“These [production] plans throw the global energy transition into question. They throw humanity’s future into question. Governments must stop saying one thing and doing another, especially as it relates to production and consumption of fossil fuels.” 

Much of the focus for climate mitigation –– in Canada and around the world –– has been on reducing demand for fossil fuels.  

Indeed, the International Energy Agency has said consumption of fossil fuels will likely peak this decade and would have to decline dramatically over the next 25 years if the world is to meet its stated climate goals.  

However, major increases in production would make progress more difficult by locking in additional fossil fuel infrastructure, increasing resistance among producing jurisdictions to the transition, and keeping prices low.  

“COP28 could be the pivotal moment where governments finally commit to the phase-out of all fossil fuels and acknowledge the role producers have to play in facilitating a managed and equitable transition,” says Michael Lazarus, a lead author on the report. 

Hopes for a consensus remain a long shot. COP28, which begins November 30, is being held in Dubai, in the oil- and gas-rich United Arab Emirates. Presiding over the summit will be Sultan Ahmed Al Jaber, head of the Emirates’ state oil company, ADNOC.  

Al Jaber said recently the COP28 should reach an agreement to phase out “unabated” fossil fuels.   That’s a vague term used to defend the continued, and even increased, use of fossil fuels so long as it includes technologies to capture carbon emissions from large production facilities, power plants or industrial factories. 

For the Liberal government, the demands for a phase-out of fossil fuel production brings increased political headaches.  

Environment Minister Steven Guilbeault has said that governments at COP28 should endorse the phase-out of “unabated” fossil fuels, a characterization that drew criticism from both sides of the issue. While environmentalists slammed the limited commitment as wholly insufficient, Western premiers protested that it demonstrated Ottawa’s intention – as Saskatchewan’s Scott Moe put it on social media – “to completely shut down our energy sector.” 

COP28 could be the pivotal moment where governments finally commit to the phase-out of all fossil fuels.

 

– Michael Lazarus, lead author of the 2023 Production Gap Report

The Liberals are already on the defensive for watering down their carbon tax with a heating oil exemption for Atlantic Canada. 

Canada’s Constitution gives to the provinces the jurisdiction over resource ownership, management and production. Liberal ministers insist that their plan for a cap on oil and gas emissions is not aimed at production levels but rather at the industry’s carbon dioxide and methane emissions.  

Provincial governments and industry officials argue that the federal government’s target for a 42% reduction in oil and gas emissions by 2030 could be achieved only by shutting down some production. 

For Ottawa to endorse an unambiguous call to phase –out production would fan the political firestorm. Undertaking negotiations toward a gradual phase-out of production would undoubtedly provoke a constitutional challenge. 

Nor should governments rely on hopes for a massive increase in facilities that capture carbon either from emission streams or directly from the atmosphere to save us. Carbon capture and storage technology works only for large-scale facilities – not the millions of oil and gas wells that yield the global supply – and it will take decades and billions of dollars for the technology to be deployed at scale. 

Let’s be clear: UNEP and its partners are not suggesting the oil and gas industry be shut down in the short term. The target is 2050, and even then, they call for oil and gas production to be cut by 75%, with carbon capture and storage used on the rest.  

However, we urgently need to start the process to ensure we meet short- and medium-terms climate goals.  

COP28 should send a strong signal: for the sake of all global citizens and the species we share this planet with, the fossil fuel era must come to a timely end.  

The post Canada on the defensive as global pressure mounts to phase out fossil fuels appeared first on Corporate Knights.

After acquiring British Columbia-based Carbon Engineering last week, Occidental hopes to build about 100 DAC plants that strip carbon dioxide from the atmosphere to bury underground, or for use in making products like concrete and aviation fuel.

“The acquisition enables Occidental to catalyze broader development partnerships for DAC deployment in the most capital efficient and valuable way,” Hollub said.

Earlier this year, she said DAC will one day help Occidental bring its operations to net-zero, allowing it to continue investing in oil extraction.

“We believe that our direct capture technology is going to be the technology that helps to preserve our industry over time,” Hollub told an oil and gas conference in March. “This gives our industry a licence to continue to operate for the 60, 70, 80 years that I think it’s going to be very much needed.”

Unlike carbon capture and storage (CCS) systems that remove carbon at the point of emission, DAC is mean to suck up and store carbon that is already in the atmosphere. It is currently the most expensive application of carbon capture, says the International Energy Agency. It’s still in the early stages of commercialization, and multi-billion-dollar investments will be needed before its proponents can be sure it will deliver as promised.

But it is also among the technologies eligible for funding under the U.S. Inflation Reduction Act. Some of Occidental’s proposed DAC plants have already been selected as federal grant recipients, Reuters says. Canada, too, is trying to support DAC technology, and is currently working out the details to issue tax credits for its deployment, writes the Canadian Press.

Carbon Engineering CEO Daniel Friedmann said the deal with Occidental will dramatically enhance the company’s ability to continue developing its technology through to commercialization.

“It will enable us to accelerate our mission to lead the world in the large-scale removal of carbon dioxide from the air and help advance our shift to a sustainable, net zero society,” he said.

But CDR is not a replacement for deep emissions reductions, said climate scientist and IPCC author Zeke Hausfather. “Anyone who says differently is selling something.”

Other scientists have also weighed in, cautioning that Occidental has inflated the role that carbon dioxide removal can play in reducing emissions, reports Climate Home News.

Selling carbon removal credits and “net-zero oil” will initially yield the most revenue for Occidental’s DAC ventures, Richard Jackson, Occidental’s president of U.S. onshore resources and carbon management, told the Wall Street Journal.

“We can turn carbon dioxide into value,” he said.

Eventually, Hollub said she expects Occidental’s clean energy efforts to become more lucrative than its chemicals division.

But critics have repeatedly warned that carbon offsets should be treated as a last resort, never taking the place of real emissions cuts. Otherwise, heavy polluters could use them as a “get out of jail free” card.

Others have said technologies like DAC should not be a major plank in net-zero schemes, as their potential is limited compared to the scale of the climate crisis. DAC is not a “silver bullet” that can live up to the hype of fossil fuel companies, and “capturing three-quarters of present carbon dioxide emissions [with DAC] would require half of present global electricity generation, and heat equivalent to half of final energy consumption,” Greenpeace observes.

But DAC does align with Big Oil’s plans for continuing production. Oil companies will have to find ways to remove as much carbon dioxide as they emit “if they want to be the last producer standing in the world,” Hollub told the Wall Street Journal.

This story first appeared in The Energy Mix.

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