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Greenhouse Gases

How Alberta is turning carbon emissions into an advantage

The Canadian province’s carbon pricing and sequestration infrastructure are helping attract investment

by Alexander H. Tullo
January 24, 2022 | A version of this story appeared in Volume 100, Issue 3

A photo of a carbon dioxide pipeline at a refinery.
Credit: Alberta Carbon Trunk Line
The Alberta Carbon Trunk Line gathers carbon dioxide from the North West Redwater Partnership refinery in Alberta.

Corporate planners usually have two main considerations when deciding where to locate big new industrial projects: access to cheap raw materials and proximity to customers.

But as corporations and countries develop strategies to reduce greenhouse gas emissions—down to zero by midcentury, in many cases—a new priority is emerging for planners: choosing a location that allows them to dispose of the carbon dioxide their new facilities will generate.

Large industrial plants are meant to last decades, so planners need a solution for carbon now if they want to hit their own net-zero targets for 2050. Increasingly, the advantage is going to places that already put a price on carbon—either through taxes or trading schemes—and have the infrastructure and geological potential to sequester CO2 below ground.

Planned Alberta carbon capture and sequestration projects

Sponsors: Canadian Natural Resources, Cenovus, ConocoPhillips, Imperial Oil, MEG Energy, Suncor Energy
Capacity: 40 million metric tons (t) per year
Highlights: The Oil Sands Pathways to Net Zero is a consortium of major oil sand operators that plan to gather CO2 from 20 locations as part of their bid to eliminate 68 million t of CO2 by 2050.

Sponsors: Pembina Pipeline, TC Energy
Capacity: 20 million t
Highlights: The companies hope to complete the project by 2027. They say their reservoir can store 2 billion t of CO2 in total.

Sponsor: Shell
Capacity: 10 million t
Highlights: The Polaris project, still awaiting a final green light, would build on Shell’s existing Quest facility but would be an order of magnitude larger and take in CO2 from third-party industrial facilities.

Sponsors: Enbridge, Capital Power
Capacity: 3 million t
Highlights: The project would draw CO2 from a Capital Power electricity plant and also be available to third-party emitters.

Sponsors: Suncor, Atco
Capacity: 2 million t
Highlights: The firms plan a hydrogen facility with 300,000 t of capacity. They would capture their own CO2 and open their sequestration capacity to third parties.

Sponsors: Six First Nations, Kanata
Capacity: Unknown
Highlights: Members of the Confederacy of Treaty Six First Nations have submitted an application to locate a carbon-capture hub on their traditional territory.

Sources: Company documents.

Alberta is one such place. The Canadian province has always attracted oil and chemical investment. It produces 4 million barrels of oil per day, about 80% of Canada’s total, and is a petrochemical powerhouse. On top of that, the province now has pipelines to transport and sequester CO2, and it boasts an innovative carbon pricing system.

Alberta’s emission strategy has rewarded it with a wave of new projects. In October, Dow unveiled plans for a net-zero CO2 emission ethylene cracker. Air Products & Chemicals plans to build a net-zero hydrogen complex in Alberta as well. These projects might be just the beginning for the province, and other regions are starting to take notice.

Jeff Pearson is president of Wolf Midstream’s carbon business, which owns and operates the Alberta Carbon Trunk Line (ACTL), a CO2 pipeline in the province. He predicts a “net-zero manufacturing hub” will develop around the Edmonton, Alberta, area. “You can feel very comfortable making commitments to this jurisdiction knowing there’s somewhere to put your carbon,” Pearson says.

The Alberta government has been assertive in putting a price on carbon emissions through a taxation and offset system. According to the International Emissions Trading Association, Alberta facilities that emit more than 100,000 metric tons (t) per year of CO2 are subject to taxes of Can$50 (US$40) per metric ton. Some 460 facilities in Alberta, including chemical plants, cement factories, and oil sand operations, face the levies, which will gradually increase to Can$170 (US$136) by 2030.

The provincial government has also been backing carbon capture and storage infrastructure. The first installation was the Quest Carbon Capture and Storage Project, which opened in 2015. Financed with nearly $700 million from the governments of Alberta and Canada, Quest is designed to capture 1.2 million t per year of CO2 from the Scotford Upgrader, a Shell-operated plant that processes bitumen from Canada’s oil sands. As of 2019, Quest had sequestered 4.8 million t of CO2 2 km underground and generated $280 million in CO2 emission offsets.

The ACTL is the first CO2 transport system available to third parties. The first two customers are the Sturgeon Refinery, run by the North West Redwater Partnership (NWR) in Sturgeon County, Alberta, and Nutrien’s ammonia plant in Redwater, Alberta.

The Sturgeon Refinery started up in 2020, built at a cost of more than $10 billion. It can refine nearly 80,000 barrels per day of diluted bitumen into diesel and other products.

Refining the tar-like bitumen requires large amounts of hydrogen, which is made by the plant’s gasification unit. The unit generates a pressurized and concentrated stream of by-product CO2 that is ideal for carbon capture and storage. In all, the refinery captures 1.3 million t of CO2 a year, about 70% of its overall emissions.

According to Jim Quinn, NWR’s vice president of engineering, the company had the foresight to include CO2 capture as part of its initial planning back in 2004. “We worked to make sure that we would be able to produce that in a pure form so that we could then capture it and use it for some other purpose,” he says.

Nutrien captures CO2 from the hydrogen-producing steam reformers at its ammonia plants and has been injecting it into the ACTL since 2019. The company can sequester 300,000 t per year of CO2 at its Redwater location.

The ACTL transports the CO2 to Enhance Energy, 240 km away in Clive, Alberta. Kevin Jabusch, Enhance’s president, explains that his company purchases CO2 from Nutrien and NWR and generates revenues from the CO2 in two ways. One is using it for enhanced oil recovery, the process of injecting CO2 to dislodge hydrocarbons trapped underground. Any CO2 that comes up with the oil is sent back into the reservoir for permanent storage. “Nothing ends up being emitted into the atmosphere,” Jabusch says.

Enhance also generates tax credits for every metric ton of CO2 it sequesters. It sells the offsets to third parties in Alberta looking to save on their $50 per metric ton tax bill.

While he won’t go into financial details, Ashley Harris, vice president of environmental performance and innovation at Nutrien, says the credits create incentives for all the companies involved that help pay for the CO2-capture infrastructure. “Ultimately, there’s a value for that credit, and then that’s shared by parties on some commercial basis,” he says.

But while the incentives might help defray the cost of carbon capture and storage from concentrated sources of CO2 like ammonia plants, they aren’t enough to attract new ammonia plants to Alberta, Harris says. Corporate sustainability goals are also driving the decision to invest in places where advanced carbon sequestration exists.

For example, ammonia currently sells for more than $1,000 per metric ton, while the incentive is roughly equal to the tax. “The revenue stream is not significant to our bottom line,” Harris says. “However, it did enable the Redwater project to be one of the most commercially viable options to decarbonize our footprint.”

To Mark Demchuk, national director of strategy and stakeholder relations for the International CCS Knowledge Centre, a Saskatchewan-based organization that consults with companies and governments about carbon-capture projects, the ACTL and the Quest project were important milestones for companies seeking places they can capture carbon. “They’ve demonstrated that large-scale projects can be done successfully in Alberta,” he says.

Demchuk expects the infrastructure will create a cluster of low-carbon facilities. “We’ve got a situation now where all of the large industrial emitters in the province across all industries, whether it is oil sands, cement, fertilizers, and various petrochemicals, have all either developed, or are in the process of developing, long-term decarbonization strategies,” he says.

The most prominent chemical project so far comes from Dow. As a centerpiece of its own goal of achieving carbon neutrality by 2050, Dow has committed to build the chemical industry’s first net-zero carbon emission ethylene cracker in Alberta.

The cracker, at Dow’s Fort Saskatchewan site, will have 1.8 million t of ethylene capacity. Part of the emission elimination will come from an efficient design modeled on Dow’s new cracker in Freeport, Texas. Because of features such as state-of-the-art furnaces, meticulous site heat integration, and hydrogen recycling, the Freeport cracker has 60% lower emissions than any other in Dow’s fleet, the company says.

You can feel very comfortable making commitments to this jurisdiction knowing there’s somewhere to put your carbon.
Jeff Pearson, president, Wolf Midstream’s carbon business

The Alberta plant will take the emission reductions even further. Instead of natural gas, its cracking furnaces will combust hydrogen generated by an autothermal reformer from methane and other cracker by-products. Dow will capture the by-product CO2 for sequestration.

Dow had been looking to make a big investment in the Americas and was also considering the US Gulf Coast and Argentina, recalls Tyler Edgington, president of Dow Canada. Like the Gulf Coast, Alberta has low-cost ethane feedstock. It also has a government that is ready to offer incentives and reduce red tape. But the carbon tax and CO2 sequestration infrastructure helped tip the decision to Alberta.

Edward Stones, Dow’s director of energy and climate change, says emission management will become an increasingly important part of investment decisions. “They’re 40- to 50-year assets, maybe more,” he says. “You know you’re going to have an investment risk if you don’t consider this initially.”

Dow says the Alberta cracker is just the first of many such initiatives. The company plans to retrofit the entire Fort Saskatchewan facility for it to achieve net-zero carbon emissions. And it is looking at carbon capture on the Gulf Coast. “I don’t think we’ll build another cracker where we couldn’t make it carbon neutral,” Edgington says.

Air Products plans to build a net-zero hydrogen complex in Edmonton by 2024 at a cost of $1.1 billion. As at Dow, the centerpiece of the project will be an autothermal reformer. The firm will supply the resulting hydrogen to customers through its regional pipeline network, compress it for local fuel-cell buses and trucks, and use it to fuel a power plant.

Other products are also on the drawing board for Alberta. Japan’s Itochu and Malaysia’s Petronas are considering a net-zero-CO2 emission ammonia joint venture. The newly formed Northern Petrochemical is considering a similar plant that would produce both ammonia and methanol.

But the province still has work to do, especially around its CO2 sequestration capacity, before it turns into a net-zero manufacturing hub.

Both Dow and Air Products mentioned tapping into the ACTL on conference calls announcing their projects. However, the commercial arrangements for sequestering carbon at both facilities aren’t set in stone. While the ACTL does pass near Dow’s site, the company isn’t “committed to any existing infrastructure,” Edgington says.

In an email, Francesco Maione, Americas president at Air Products, says his company is “working with local companies to develop partnerships” and that the “Alberta Carbon Trunk Line is an asset that Air Products is working to utilize.”

Currently there is no place in Alberta to store additional CO2. The ACTL can carry 14.6 million t of CO2 per year and is operating at about 10% capacity. However, ACTL’s customer, Enhance Energy, only has enough of its own CO2 requirements for enhanced oil recovery to accommodate Nutrien and NWR.

Wolf’s Pearson sees a chicken-and-egg problem. “Until the infrastructure was in place, nobody was going to spend the money on the capture,” he says. Now, he says, the pipeline infrastructure is available. And with companies like Dow and Air Products making commitments to capture CO2, other firms are starting to develop sequestration projects to store it.

The Alberta government has launched a competitive process to grant pore-space rights in saline aquifers for sequestering CO2. And a half-dozen other projects are percolating. For example, Shell is planning a storage project, called Polaris, that would be more than eight times as large as its current Quest operation. Pembina Pipeline and TC Energy are contemplating building 20 million t of annual CO2 storage capacity, representing about 10% of the CO2 emissions of the entire province.

As carbon-capture infrastructure develops in Alberta, other regions and countries are looking to get into the game. “The Gulf Coast is going to have carbon capture and sequestration. It’s a question of when and how much,” Edgington says.

In 2018, the US enacted Section 45Q tax credits, which by 2026 will be worth $50 per metric ton of sequestered CO2 and $35 per metric ton of CO2 used in enhanced oil recovery. “It is evolving to where carbon capture is becoming quite interesting, particularly with the 45Q tax credit being at $50,” Nutrien’s Harris says. His company has been sending CO2 to Louisiana’s Denbury CO2 pipeline for use in enhanced oil recovery since 2013.

In October, Air Products announced that it will spend $4.5 billion in Louisiana on what might be the world’s largest net-zero-CO2 ammonia facility. The project is intended to capture and sequester 5 million t of CO2 per year in storage infrastructure, which Air Products itself plans to build.

And earlier this month, a Wolf Midstream affiliate announced a deal to build a pipeline to transport CO2 from ADM’s two ethanol plants in Iowa to the corn refiner’s facility in Decatur, Illinois, where it already sequesters CO2 underground.

Dow’s Stones says the trends that are beginning in Alberta will spread globally and transform the entire chemical industry. “I would say that long-term globally, the solution that will work is an integrated hub on CO2 and probably with an adjacent integrated hub on hydrogen, just like today’s hub based on natural gas,” he says. “That’s what it will take to drive a 2050-ready petrochemical facility.”



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