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Glencore-Teck deal reveals the irony of coal: Profitable and vital, yet endlessly shunned

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From the MacDonald Laurier Institute

By Heather Exner-Pirot

Coal is not going anywhere, and while some countries will benefit, Canada will not be among them

In many ways, the US$8.9-billion deal Glencore has struck for Teck Resources’ coal assets represents an elegant split that plays to each company’s strengths.

Teck, the Canadian miner, can now focus on its core base metals business, in particular copper, as it bets on strong returns in the years to come. Swiss commodities giant Glencore can build up its coal empire, adding the steelmaking coal assets to its vast thermal coal trade.

But the deal also reveals how coal has its own set of rules. Despite how profitable and strategic Teck’s coal resources are, they will soon come under foreign control. It is hard to imagine this unfolding the same way for any other commodity.

Coal is an essential, ubiquitous material. It is the workhorse of the global power sector, accounting for more than a third of global electricity generation. And it is indispensable in steelmaking. The burning of coke, a coal-based fuel, produces the carbon monoxide needed to convert iron ore into a liquid, alongside high temperatures. The majority of steel in the world is made with coking coal, also known as metallurgical coal.

Owing to its carbon intensity, it has a terrible reputation. Investors and shareholders, not to mention Western governments, shun it. Teck’s intention to spin off its coal business is linked to shareholder desires to see a decoupling of its metals and coal businesses out of environmental concerns, which have weighed on its valuation. Even as it pursues Teck’s coal assets, Glencore is doing the same; it plans to separate its metals and coal businesses within two years and sought Teck’s premium steelmaking coal to make its other coal holdings more palatable.

But shareholder distaste for coal is increasingly divorced from its economics. Coal is still highly profitable. Last year witnessed high prices and record demand, in part owing to the fallout from the Russian invasion of Ukraine. Both Teck and Glencore benefited greatly. Teck earned record profits of $4.9-billion, with coal accounting for 75 per cent of that. Glencore’s core profit rose 60 per cent to a record US$34.1-billion, more than half of which came from coal production.

Teck’s steelmaking coal assets in B.C.’s Elk Valley are world-class – high-quality, with decades of reserves and a low carbon intensity relative to other deposits. Glencore’s deal for them will see it partnering with Japan’s Nippon Steel and South Korea’s PISCO, who will take minority stakes. The fact that the deal includes two of the world’s biggest steel producers is evidence that these coal assets have long-term customers. This deal is not about Teck unloading a bad asset; it is about removing the ESG noose around its neck.

That’s poor justification for letting such vital assets end up in foreign hands. Yet the federal government will likely let the deal happen.

Federal scrutiny of foreign investment and takeovers in our domestic mining sector has grown of late, as the need for friendly sources of critical minerals grows. As The Globe and Mail reported last month, Canadian firms have mainly been the targets, rather than pursuers, of acquisitions in the sector in the past decade. Canada has toughened the Investment Canada Act as a result.

While the Teck-Glencore deal will raise similar concerns, it has been designed to skirt them. Teck’s news release could have been written by Ottawa. It aligns with the federal government’s recent Critical Minerals Strategy and commits to remaining a Canadian-based miner focused on “future-oriented metals,” “an electric vehicle battery recycling facility” and support for “junior Canadian mining and exploration companies.” It also preserves B.C.’s coal mining jobs and revenues.

There’s a parallel universe where a G7 country protects its most exquisite metallurgical coal deposit, required to produce a critical material for any advanced economy, energy system or military. That introduces policy to reshore and build up its domestic steel industry in an era of growing geopolitical turbulence.

The world in 2023 is not this place. And Canada is not that G7 country. Indeed, the world view of the current federal and B.C. governments sees the decline of coal as both imminent and necessary. There is no way they will make the argument that the material is a strategic resource that must remain under Canadian ownership.

But coal is not going anywhere. Some countries will benefit, economically and strategically, from controlling it. Canada will not be among them.

Heather Exner-Pirot is the director of energy, natural resources and environment at the Macdonald-Laurier Institute.

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Alberta

The permanent CO2 storage site at the end of the Alberta Carbon Trunk Line is just getting started

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Wells at the Clive carbon capture, utilization and storage project near Red Deer, Alta. Photo courtesy Enhance Energy

From the Canadian Energy Centre

By Deborah Jaremko

Inside Clive, a model for reducing emissions while adding value in Alberta

It’s a bright spring day on a stretch of rolling farmland just northeast of Red Deer. It’s quiet, but for the wind rushing through the grass and the soft crunch of gravel underfoot.

The unassuming wellheads spaced widely across the landscape give little hint of the significance of what is happening underground.

In just five years, this site has locked away more than 6.5 million tonnes of CO₂ — equivalent to the annual emissions of about 1.5 million cars — stored nearly four CN Towers deep beneath the surface.

The CO₂ injection has not only reduced emissions but also breathed life into an oilfield that was heading for abandonment, generating jobs, economic activity and government revenue that would have otherwise been lost.

This is Clive, the endpoint of one of Canada’s largest carbon capture, utilization and storage (CCUS) projects. And it’s just getting started.

 

Rooted in Alberta’s first oil boom

Clive’s history ties to Alberta’s first oil boom, with the field discovered in 1952 along the same geological trend as the legendary 1947 Leduc No. 1 gusher near Edmonton.

“The Clive field was discovered in the 1950s as really a follow-up to Leduc No. 1. This is, call it, Leduc No. 4,” said Chris Kupchenko, president of Enhance Energy, which now operates the Clive field.

Over the last 70 years Clive has produced about 70 million barrels of the site’s 130 million barrels of original oil in place, leaving enough energy behind to fuel six million gasoline-powered vehicles for one year.

“By the late 1990s and early 2000s, production had gone almost to zero,” said Candice Paton, Enhance’s vice-president of corporate affairs.

“There was resource left in the reservoir, but it would have been uneconomic to recover it.”

Facilities at the Clive project. Photo courtesy Enhance Energy

Gearing up for CO2

Calgary-based Enhance bought Clive in 2013 and kept it running despite high operating costs because of a major CO2 opportunity the company was developing on the horizon.

In 2008, Enhance and North West Redwater Partnership had launched development of the Alberta Carbon Trunk Line (ACTL), one of the world’s largest CO2 transportation systems.

Wolf Midstream joined the project in 2018 as the pipeline’s owner and operator.

Completed in 2020, the groundbreaking $1.2 billion project — supported by the governments of Canada and Alberta — connects carbon captured at industrial sites near Edmonton to the Clive facility.

“With CO2 we’re able to revitalize some of these fields, continue to produce some of the resource that was left behind and permanently store CO2 emissions,” Paton said.

Map of the Alberta Carbon Trunk Line courtesy of Wolf Midstream

An oversized pipeline on purpose

Each year, about 1.6 million tonnes of CO2 captured at the NWR Sturgeon Refinery and Nutrien Redwater fertilizer facility near Fort Saskatchewan travels down the trunk line to Clive.

In a unique twist, that is only about 10 per cent of the pipeline’s available space. The project partners intentionally built it with room to grow.

“We have a lot of excess capacity. The vision behind the pipe was, let’s remove barriers for the future,” Kupchenko said.

The Alberta government-supported goal was to expand CCS in the province, said James Fann, CEO of the Regina-based International CCS Knowledge Centre.

“They did it on purpose. The size of the infrastructure project creates the opportunity for other emitters to build capture projects along the way,” he said.

CO2 captured at the Sturgeon Refinery near Edmonton is transported by the Alberta Carbon Trunk Line to the Clive project. Photo courtesy North West Redwater Partnership

Extending the value of aging assets

Building more CCUS projects like Clive that incorporate enhanced oil recovery (EOR) is a model for extending the economic value of aging oil and gas fields in Alberta, Kupchenko said.

“EOR can be thought of as redeveloping real estate,” he said.

“Take an inner-city lot with a 700-square-foot house on it. The bad thing is there’s a 100-year-old house that has to be torn down. But the great thing is there’s a road to it. There’s power to it, there’s a sewer connection, there’s water, there’s all the things.

“That’s what this is. We’re redeveloping a field that was discovered 70 years ago and has at least 30 more years of life.”

The 180 existing wellbores are also all assets, Kupchenko said.

“They may not all be producing oil or injecting CO2, but every one of them is used. They are our eyes into the reservoir.”

CO2 injection well at the Clive carbon capture, utilization and storage project. Photo for the Canadian Energy Centre

Alberta’s ‘beautiful’ CCUS geology

The existing wells are an important part of measurement, monitoring and verification (MMV) at Clive.

The Alberta Energy Regulator requires CCUS projects to implement a comprehensive MMV program to assess storage performance and demonstrate the long-term safety and security of CO₂.

Katherine Romanak, a subsurface CCUS specialist at the University of Texas at Austin, said that her nearly 20 years of global research indicate the process is safe.

“There’s never been a leak of CO2 from a storage site,” she said.

Alberta’s geology is particularly suitable for CCUS, with permanent storage potential estimated at more than 100 billion tonnes.

“The geology is beautiful,” Romanak said.

“It’s the thickest reservoir rocks you’ve ever seen. It’s really good injectivity, porosity and permeability, and the confining layers are crazy thick.”

Suitability of global regions for CO2 storage. Courtesy Global CCS Institute

CO2-EOR gaining prominence 

The extra capacity on the ACTL pipeline offers a key opportunity to capitalize on storage potential while addressing aging oil and gas fields, according to the Alberta government’s Mature Asset Strategy, released earlier this year.

The report says expanding CCUS to EOR could attract investment, cut emissions and encourage producers to reinvest in existing properties — instead of abandoning them.

However, this opportunity is limited by federal policy.

Ottawa’s CCUS Investment Tax Credit, which became available in June 2024, does not apply to EOR projects.

“Often people will equate EOR with a project that doesn’t store CO2 permanently,” Kupchenko said.

“We like to always make sure that people understand that every ton of CO2 that enters this project is permanently sequestered. And we take great effort into storing that CO2.”

The International Energy Forum — representing energy ministers from nearly 70 countries including Canada, the U.S., China, India, Norway, and Saudi Arabia — says CO₂-based EOR is gaining prominence as a carbon sequestration tool.

The technology can “transform a traditional oil recovery method into a key pillar of energy security and climate strategy,” according to a June 2025 IEF report.

Drone view of the Clive project. Photo courtesy Enhance Energy

Tapping into more opportunity

In Central Alberta, Enhance Energy is advancing a new permanent CO2 storage project called Origins that is designed to revitalize additional aging oil and gas fields while reducing emissions, using the ACTL pipeline.

“Origins is a hub that’s going to enable larger scale EOR development,” Kupchenko said.

“There’s at least 10 times more oil in place in this area.”

Meanwhile, Wolf Midstream is extending the pipeline further into the Edmonton region to transport more CO2 captured from additional industrial facilities.

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Alberta

Canadian Oil Sands Production Expected to Reach All-time Highs this Year Despite Lower Oil Prices

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From Energy Now

S&P Global Commodity Insights has raised its 10-year production outlook for the Canadian oil sands. The latest forecast expects oil sands production to reach a record annual average production of 3.5 million b/d in 2025 (5% higher than 2024) and exceed 3.9 million b/d by 2030—half a million barrels per day higher than 2024. The 2030 projection is 100,000 barrels per day (or nearly 3%) higher than the previous outlook.

The new forecast, produced by the S&P Global Commodity Insights Oil Sands Dialogue, is the fourth consecutive upward revision to the annual outlook. Despite a lower oil price environment, the analysis attributes the increased projection to favorable economics, as producers continue to focus on maximizing existing assets through investments in optimization and efficiency.


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While large up-front, out-of-pocket expenditures over multiple years are required to bring online new oil sands projects, once completed, projects enjoy relatively low breakeven prices.

S&P Global Commodity Insights estimates that the 2025 half-cycle break-even for oil sands production ranged from US$18/b to US$45/b, on a WTI basis, with the overall average break-even being approximately US$27/b.*

“The increased trajectory for Canadian oil sands production growth amidst a period of oil price volatility reflects producers’ continued emphasis on optimization—and the favorable economics that underpin such operations,” said Kevin Birn, Chief Canadian Oil Analyst, S&P Global Commodity Insights. “More than 3.8 million barrels per day of existing installed capacity was brought online from 2001 and 2017. This large resource base provides ample room for producers to find debottlenecking opportunities, decrease downtime and increase throughput.”

The potential for additional upside exists given the nature of optimization projects, which often result from learning by doing or emerge organically, the analysis says.

“Many companies are likely to proceed with optimizations even in more challenging price environments because they often contribute to efficiency gains,” said Celina Hwang, Director, Crude Oil Markets, S&P Global Commodity Insights. “This dynamic adds to the resiliency of oil sands production and its ability to grow through periods of price volatility.”

The outlook continues to expect oil sands production to enter a plateau later this decade. However, this is also expected to occur at a higher level of production than previously estimated. The new forecast expects oil sands production to be 3.7 million b/d in 2035—100,000 b/d higher than the previous outlook.

Export capacity—already a concern in recent years—is a source of downside risk now that even more production growth is expected. Without further incremental pipeline capacity, export constraints have the potential to re-emerge as early as next year, the analysis says.

“While a lower price path in 2025 and the potential for pipeline export constraints are downside risks to this outlook, the oil sands have proven able to withstand extreme price volatility in the past,” said Hwang. “The low break-even costs for existing projects and producers’ ability to manage challenging situations in the past support the resilience of this outlook.”

* Half-cycle breakeven cost includes operating cost, the cost to purchase diluent (if needed), as well as an adjustment to enable a comparison to WTI—specifically, the cost of transport to Cushing, OK and quality differential between heavy and light oil.

About S&P Global Commodity Insights

At S&P Global Commodity Insights, our complete view of global energy and commodity markets enables our customers to make decisions with conviction and create long-term, sustainable value.

We’re a trusted connector that brings together thought leaders, market participants, governments, and regulators and we create solutions that lead to progress. Vital to navigating commodity markets, our coverage includes oil and gas, power, chemicals, metals, agriculture, shipping and energy transition. Platts® products and services, including leading benchmark price assessments in the physical commodity markets, are offered through S&P Global Commodity Insights. S&P Global Commodity Insights maintains clear structural and operational separation between its price assessment activities and the other activities carried out by S&P Global Commodity Insights and the other business divisions of S&P Global.

S&P Global Commodity Insights is a division of S&P Global (NYSE: SPGI). S&P Global is the world’s foremost provider of credit ratings, benchmarks, analytics and workflow solutions in the global capital, commodity and automotive markets. With every one of our offerings, we help many of the world’s leading organizations navigate the economic landscape so they can plan for tomorrow, today. For more information visit https://www.spglobal.com/commodity-insights/en.

SOURCE S&P Global Commodity Insights

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