Growing global demand for secure, reliable energy is creating a major opportunity for Canada, according to experts who say Asia’s growing needs underscore the case for more export capacity on the West Coast.

“I wish there were a few more Canadas in the world, so that we can have a much more reliable and sustainable global energy system,” the International Energy Agency (IEA)’s executive director Fatih Birol said during a recent trip to Canada.

Even before recent disruptions tied to conflict in the Middle East, the need for more Canadian energy in global markets was clear.

Growing shipments to Asia

The evidence can be seen in growing shipments from two newly completed pieces of export infrastructure: the Trans Mountain oil pipeline expansion and the LNG Canada natural gas export terminal.

In April, LNG Canada reached a key ramp-up milestone with its first exports of one million tonnes of liquefied natural gas (LNG) in a single month. Since start-up in June 2025, every shipment from the facility in Kitimat, B.C., has gone to Asia, led by South Korea, according to the Canada Energy Regulator.

Meanwhile, Trans Mountain reports that since May 2024, more than half of ocean exports from its expansion project have gone to Asia, primarily China and South Korea.

Demand growth for decades

But it’s just the tip of the iceberg, according to energy analysts and researchers who argue that rising global consumption — particularly in Asia — means Canada needs another oil pipeline to the Pacific coast, alongside new LNG export terminals under construction.

“The Pacific Basin is still underserved. Asia is the world’s biggest energy market, and Indian and Southeast Asian growth is just taking off,” said Heather Exner-Pirot, senior fellow and director of energy, natural resources and environment at the Macdonald-Laurier Institute.  

That presents a major opportunity for both Canada’s natural gas and oil resources. 

Asian markets will continue to drive growth in oil and gas demand for decades, the International Energy Agency (IEA) projects.

Asia’s need for both oil and natural gas

By 2050, natural gas demand in the Asia-Pacific region is expected to be nearly 60 per cent higher than it is today, according to the IEA’s latest outlook.

Meanwhile, regional oil demand is projected to grow by close to 20 per cent.

Globally, demand for extra-heavy oil and bitumen like what Canada produces is expected to rise by nearly 40 per cent over the next 25 years.

Many Asian refineries are configured to process heavier crude grades like those produced in Canada.

China, the world’s largest oil importer, alone represents enormous potential for export growth.

Mutually beneficial energy supply

The Asia Pacific Foundation of Canada (APF) argues that Canada is well positioned as China looks to diversify its suppliers and reduce reliance on Russia and the Middle East to feed its refineries and petrochemical sector.

In addition to being more politically stable than many global suppliers, Canada can ship oil and gas to Asia in about half the time it takes from the U.S. Gulf Coast through the Panama Canal.

“The result is mutually beneficial: Canada secures better revenues and greater market diversification while China gains a stable, low-cost oil supply,” wrote APF’s Xiaoting (Maya) Liu and Rachael Gurney.

A new oil pipeline from Alberta to the West Coast should be viewed as insurance, providing options in an uncertain world for both Canada and crude oil buyers, wrote Jackie Forrest, executive director of the ARC Energy Research Institute, in The Globe and Mail. 

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A new agreement between Alberta and Ottawa aims to address long-standing concerns about how major projects including oil sands, pipelines and carbon capture are reviewed.

It supports recently introduced provincial legislation to ensure approvals for qualified projects are completed within 120 days.

By reducing duplication without compromising environmental protection, the intent is to make Alberta projects more attractive to investors, says Brad Gilmour, partner in the Regulatory, Indigenous and Environmental Group of Osler’s Calgary office.

Here’s what Gilmour had to say about what the agreement means.

CEC: What is environmental assessment, and how does it apply to major projects?

BG: Environmental assessment is a process right at the beginning stages to gather information about a project and incorporate that into [regulatory] decision-making, but it’s not the end of the process in terms of protection of the environment. It is really the beginning. 

There has historically been a problem where we’ve got comprehensive environmental assessment legislation at the provincial level and at the federal level, and both statutes apply. You’re inevitably reviewing the same types of issues, and that creates significant inefficiencies and adds to delays, uncertainty and complexity of the process. 

The key is who really regulates these activities, generally, on a day-to-day basis. In so many cases, it’s the province, so that’s where the expertise is. We have expert regulatory authorities that oversee the life cycle of these activities, not merely at the environmental assessment stage.

The more the province and the federal government can work together to avoid duplication, create a higher degree of certainty and reduce timelines, the more that’s going to incentivize investors to look at doing projects in Alberta.

CEC: What kinds of projects does this agreement impact?

BG: It would include oil sands projects, electrical generation projects, things like carbon capture and storage projects and mining projects. 

It’s pretty much everything we do in the natural resources and energy sectors in Alberta, with the exception of things like pipelines that cross provincial boundaries or international boundaries, which are areas of federal jurisdiction. In those cases, the federal government will also cooperate with the province. 

CEC: What does this agreement change?

BG: Number one, it signals greater cooperation between the province and the federal government in terms of environmental assessment, which is ultimately a good thing. 

The regulation of environmental assessment between the two jurisdictions has been contentious over the last several years, including ongoing litigation with respect to the constitutionality of the Impact Assessment Act. 

Importantly, the agreement creates a single environmental assessment process. It follows that one-project, one-assessment model that both levels of government have been talking about. 

It makes Alberta the lead on environmental assessments for projects that are primarily regulated by the province. It places the responsibility primarily in the appropriate jurisdiction, and with the regulators that have the greatest degree of expertise over those activities. 

There are other provinces that have similar agreements with the federal government: Nova Scotia, Prince Edward Island, Ontario, New Brunswick and British Columbia.

CEC: Does the agreement make environmental protection requirements more lenient?

BG: It doesn’t, in my view, do anything to take away from environmental protection. What it does is it focuses the environmental assessment process, avoids duplication, and lets the jurisdiction with the primary expertise lead the process.

For most of what we do in the energy and natural resources sector, the environmental effects are not a mystery, and often our environmental assessment processes treat them as if they are a mystery. But they’re well understood, as well as the means to mitigate them throughout the entire life cycle of the activity. 

CEC: Does the agreement change consultation with Indigenous communities?

BG: Both levels of government are very clear in the agreement that they will continue to be committed to meaningful participation of Indigenous groups in the assessment process and to respect their rights that are protected under Section 35 of the constitution. 

What it signals is a bit of a change that is consistent with the idea that the primary regulatory authority takes the lead. It recognizes that where a project is primarily regulated by the province, that the province is best placed to undertake the consultation with Indigenous peoples in relation to that activity. 

CEC: Does the agreement impact Alberta’s constitutional challenge of the federal Impact Assessment Act?

BG: It does not. In fact, the agreement specifically acknowledges that Alberta is challenging the constitutionality of the Impact Assessment Act and that the matter is before the courts. 

The province’s concern – that the federal government was overreaching in terms of its jurisdiction over environmental matters through the Impact Assessment Act – was validated in the October 2023 decision of the Supreme Court of Canada, and now the Act has been amended. 

That is now again being challenged by the province, being heard by the Alberta Court of Appeal. A decision in that regard is pending.

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The federal government is following through on a key element of its energy accord with Alberta.

In its spring economic update, Ottawa confirmed plans to extend the carbon capture, utilization and storage (CCUS) investment tax credit to projects that include enhanced oil recovery (EOR).

EOR projects were notably excluded from Ottawa’s CCUS investment tax credit when it was rolled out in 2024.

“We were always puzzled; we were always concerned that EOR was removed from the conversation,” Mark Scholz, president of the Canadian Association of Energy Contractors, told reporters at the group’s December state of the industry luncheon. 

“I mean, EOR is a game changer for the conventional business.”

Enhanced oil recovery involves injecting CO₂ captured from industrial sources deep underground into mature oil reservoirs to help increase production. 

The CO₂ helps oil flow more easily out of the porous rock, making it more efficient to extract, while the injected CO₂ remains trapped underground. This process can extend the life of existing oil production while also enabling large-scale storage of greenhouse gases.

Six of Canada’s eight operating commercial-scale CCUS projects involve using captured carbon for EOR.

One example is the Weyburn-Midale project, which since 2000 has safely stored CO₂ equivalent to the annual emissions of more than 9.5 million cars—exceeding the total number of gasoline-powered light-duty vehicles in Ontario.

Having produced more than 600 million barrels of oil, Weyburn is one of the world’s longest-running CO₂ EOR projects. It still has decades of remaining potential, executives with owner Whitecap Resources said at the company’s investor day in January 2026.

In Alberta, Enhance Energy’s Clive sequestration project near Red Deer permanently stores more than 1.5 million tonnes of CO₂ each year while producing oil through EOR.

The project helps reduce emissions from Alberta’s large industries while making use of existing infrastructure and addressing legacy liabilities from past oil and gas operations, said Enhance Energy vice-president Candice Paton.

“The inclusion of EOR in the CCUS ITC as a permanent geological storage option for industrial CO2 allows companies like Enhance to continue having a positive impact in both emissions reductions and energy production by repurposing existing assets,” she said.

Excluding enhanced oil recovery from federal investment incentives never made sense, lawyers Scott Masson and Tom Collopy of MLT Aikins’ energy group wrote in an analysis prior to the Canada-Alberta agreement.

“EOR is not a novel technology in Canada. These facilities, such as the Boundary Dam Power Station in Estevan, Saskatchewan, demonstrate that EOR is a natural extension of CCUS operations,” they wrote.

Including EOR in the investment tax credit would make the technology more financially viable for energy producers.

As a result, “Canada can simultaneously advance its environmental goals and economic interests,” they wrote. 

Along with existing regimes in Alberta and Saskatchewan, this will encourage more producers to consider using CO2-EOR to extend the value of mature assets, Masson told CEC. 

“This significantly changes the economics of a project,” he said. 

“When you are looking at CCUS projects, the incentive structures required to build them are important. We’re seeing a lot of projects in the CCUS space hovering around this final investment decision,” Masson said. 

“A lot of organizations have had problems getting projects across the line, and this change helps remove a sticking point that a lot of our clients in this space have had when it comes to CCUS.”

Calgary-based Conifer Energy welcomed the expansion of Canada’s CCUS framework to include EOR, saying it will help enable the long-term investment needed to advance major decarbonization infrastructure.

The company said access to the federal tax credit “materially improves” the economics of its future Alberta projects, which will permanently store CO₂ while supporting jobs and generating government royalties.

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Large-scale habitat restoration in Alberta is accelerating to support iconic caribou populations.

The focus is on legacy seismic lines — straight, flattened clearings cut through the boreal forest decades ago for oil and gas exploration, often up to eight metres wide to accommodate large equipment.

While today’s oil and gas operators no longer use these methods, the forest in many areas has struggled to regenerate on its own.

Now, it’s got some help. 

Revegetation of legacy seismic lines has increased by nearly 7,000 per cent since 2019, according to new data from Alberta Environment and Parks. 

More than 6,100 kilometres have been treated since the launch of Alberta’s Caribou Habitat Recovery Program, compared to just 87 kilometres between 2015 and 2019.  

“What’s been done in the past five years with the resources and exposure committed to recovering these disturbances is impressive progress,” said Jesse Tigner, a Pincher Creek, Alta.-based ecologist who has both researched and restored seismic lines through his company SwampDonkey Solutions.

The record pace is set to continue, with the province announcing agreements with two major energy companies to invest nearly $12 million in replanting legacy lines in caribou ranges where they operate.

Seismic lines and caribou

The first seismic survey in Alberta was carried out in 1929 to support development of the Turner Valley oilfield. 

For most of the 20th century, seismic lines in the province were cut with heavy machinery to make room for large equipment that uses energy waves to map oil and gas deposits beneath the surface. 

While many have not been used for decades, more than 200,000 kilometres of legacy seismic lines remain in Alberta’s caribou ranges.

Researchers have identified restoring these legacy lines as crucial to rebuilding habitat for the species.

That’s because the clearings have created pathways that make it easier for wolves to hunt caribou, which are considered threatened in Canada.

“Legacy lines allow wolves to move much further and faster than forests without lines,” Tigner said. 

Used since the 1990s,. low-impact seismic lines are smaller and recover more effectively on their own, according to a study co-authored by Tigner in the Canadian Journal of Forest Research.

Industry investment builds momentum

Since 2019, more than $90 million has been invested in assessing and restoring legacy seismic lines under Alberta’s Caribou Habitat Recovery Program, the province says.

New agreements with TC Energy and Syncrude will add nearly $12 million.

Pipeline operator TC Energy will invest $5 million to restore legacy seismic lines in the Little Smoky caribou range in west-central Alberta, while oil sands producer Syncrude has committed $6.95 million to restoration in the Richardson range in the province’s northeast.

Tigner, who has worked on restoring legacy lines in both British Columbia and Alberta, sees industry participation as important in addressing the issue.

“Some oil sands companies have driven the work and have done a phenomenal job of restoring lines,” he said. 

Oil sands-led projects drive restoration

The oil sands industry has invested in caribou habitat restoration for nearly two decades, said Kendall Dilling, president of the Oil Sands Alliance, which represents its five largest producers.

“Several projects led by industry have piloted the methods and techniques used to restore caribou habitat,” he said.

Examples include the Boreal Ecosystem Recovery and Assessment (BERA) project,  Cenovus Energy’s Caribou Habitat Restoration Project and the Algar Seismic Restoration Pilot Project.

The ongoing BERA project brings together researchers, industry and government to study how industrial activity affects the boreal forest and how to restore disturbed landscapes.

Cenovus Energy’s $32-million, 10-year program, launched in 2016, restores legacy seismic lines to help protect threatened woodland caribou near its oil sands operations. 

Recognized with an Alberta Emerald Award in 2024, the project has treated more than 100,000 hectares and planted 1.6 million trees, making it the largest of its kind globally.

Meanwhile, the Algar project, carried out between 2012 and 2015, restored seismic lines in caribou habitat southwest of Fort McMurray. 

After restoration, researchers used 73 camera traps to monitor how caribou and other wildlife responded.

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As Canada moves to diversify markets for its vast oil and gas resources, experts say one reality remains: the United States will continue to be its largest energy customer.

Maintaining and strengthening that relationship is critical to North American energy security amid global instability and shifting U.S. policies.

“Market diversification for the oil and natural gas industry is not about ‘replacement.’ Diversification means growing our customer base, growing production, growing exports, and growing the Canadian economy,” said Lisa Baiton, CEO of the Canadian Association of Petroleum Producers. 

“We should work to forge a renewed continental energy alliance that is attuned to new global realities.”

An integrated energy machine

A recent analysis by the Montreal Economic Institute (IEDM) outlines the scale of current Canada-U.S. energy relationship. 

In 2024, Canada exported $169.8 billion worth of hydrocarbons — including crude oil, natural gas, natural gas liquids and refined petroleum products — to the United States. 

Led by crude oil, that accounts for 22 per cent of all Canadian goods exports and the bulk of the U.S.’s imported energy supply.

The trade flows in both directions, with Ontario, Quebec and the Atlantic region driving $33.4 billion of U.S. oil and gas imports in the same year. 

“In many ways, the border is an afterthought for this integrated North American energy machine, which has kept churning for a century, regardless of political winds,” wrote IEDM researchers Taylor MacPherson and Gabriel Giguère.

“But we can’t take it for granted; we must be steadfast in protecting this unique, mutually beneficial relationship.”

Growing pressures from global instability

The long-standing North American partnership is being tested by geopolitical uncertainty. 

Wars involving Ukraine and Iran have driven volatility in global energy markets. At the same time, the U.S. has introduced tariffs and incentives aimed at strengthening domestic energy supply chains.

While the U.S. often describes its strategy as one of “energy dominance,” that does not necessarily mean independence from Canada. 

As production of light oil from the Permian Basin has grown, so too have imports of heavier Canadian crude, primarily from Alberta’s oil sands.

Many U.S. refineries are built for heavy oil, particularly in the Midwest and Gulf Coast — but the U.S. doesn’t produce much of it, RBN Energy analyst Jason Lindquist noted recently.

“[This] makes heavy crude from nearby Canada and Latin America essential,” he wrote in a March research note. 

Canadian oil and gas underpins U.S. energy exports

Since the United States lifted its oil export ban in 2015, its light crude exports have surged, averaging about 4 million barrels per day last year, according to the U.S. Energy Information Administration (EIA).

That’s roughly equal to the volume of Canadian oil – primarily heavy oil – that the U.S. imported over the same period.

America depends on Canada to complement its natural gas supply as well. 

The U.S. is now the world’s largest liquefied natural gas (LNG) exporter, yet its natural gas imports have remained steady since LNG exports began in 2016. 

In 2025, 99.7 per cent of those imports came from Canada, according to the EIA.

Strengthening the Canada-U.S. energy relationship

While diversification work continues, observers say Canada must also keep strengthening the partnerships that bind its energy system to that of the United States.

The Washington D.C.-based Atlantic Council has advocated for a North American-wide approach. 

It urges Canada, the U.S. and Mexico to pursue a continental energy security strategy that aligns emissions reduction policies, regulatory systems and infrastructure development plans to give all three countries a global advantage.

The former CEO of the Canada Energy Regulator says Canada’s importance as a reliable energy supplier is increasing as energy prices spike amid conflict in the Middle East and a review of the Canada-United States-Mexico (CUSMA) trade agreement.

“The volatility of the current situation will make Canada more attractive as an investment location because we are seen as stable,” Gitane De Silva said in a recent interview. 

The IEDM argues that Canada needs to adopt clear “energy diplomacy” objectives to advance commercial deals with key international customers.

“As North America’s share of global oil and gas trade grows, every extra barrel or cubic foot we move strengthens our allies, thins our adversaries’ leverage, and maximizes value for the benefit of all Canadians,” MacPherson and Giguère concluded.

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The Port of Vancouver has emerged as a lifeline for Asian oil refiners amid disruption of the vital shipping route through the Strait of Hormuz, according to ATB Cormark Capital Markets.

Tankers calling at the port’s Westridge Marine Terminal now have access to an expanded, reliable supply of oil from Alberta, thanks to the Trans Mountain pipeline. 

Not only do these barrels have clear sailing to Asian ports, analysts say they’re just the type of oil Asian refiners are increasingly looking for. 

About half the oil flowing through the pipeline is considered “heavy,” one of the grades most affected by the Strait of Hormuz closure, ATB said.

“Canadian heavy oil could become a premium global asset,” managing director of institutional equity research Patrick O’Rourke wrote on Mar. 2.

SAGD oil sands project in northern Alberta. Photo courtesy Cenovus Energy

Stability in a volatile market

It’s a sentiment that was building before the new conflict in the Middle East.

“Beyond price, Canada offers something increasingly valuable — a large, stable and reliable supply of heavy crude,” Studio.Energy director of research Carmen Velasquez wrote in November. 

“At a time when geopolitical risk is reshaping energy trade flows…this reliability is becoming a strategic differentiator, not just a commercial one.” 

Why heavy oil matters

Exported mainly from Alberta’s oil sands, heavy oil is one of Canada’s biggest energy assets. 

Thick and gooey, it requires diluent for transportation and complex processing to produce gasoline, jet fuel and petrochemicals used in everyday items.

The large-scale petrochemical refineries in Asia that are driving oil demand growth can pair well with Alberta’s heavy oil, Velasquez said.

“In recent years, [China] has invested heavily in new mega-refineries and upgraded existing ones to handle heavier and more complex crude slates,” she said.

Zhejiang Petrochemical Complex in in Zhejiang, China. Photo courtesy Zhejiang Petroleum and Chemical Co.

Asia’s growing appetite

China is Asia’s “heavy oil hub,” RBC director of energy policy Shaz Merwat wrote in a November research note. 

“China is sharply pivoting into petrochemicals, aiming to take Japanese and Korean market share,” Merwat said. 

“India, too, is expected to see oil imports grow 1.5 million barrels per day by 2035 as both countries seek steady supplies of heavy and sour crude,” he said. 

“Today, that supply originates from the Middle East, Russia and Venezuela, creating an opening for a stable, Western entrant.”

Canadian barrels gaining a foothold

Canadian heavy oil has started building a footprint in Asia thanks to the Trans Mountain expansion and “re-exports” — Western Canadian barrels shipped from terminals on the U.S. Gulf Coast.

Both China and India have purchased Canadian oil from Trans Mountain since the expanded pipeline went into service in May 2024, the company reports.

Courtesy Trans Mountain Corporation

While China leads overseas sales from Trans Mountain, India is a regular buyer of U.S. Gulf Coast re-exports, according to RBN Energy.

Courtesy RBN Energy

Demand keeps climbing

“Besides ongoing efforts to expand the Chinese customer base, India and Southeast Asia are the most promising growth markets for Canadian crude,” Studio.Energy’s Velasquez said. 

“And this is no small opportunity.”

The International Energy Agency projects oil demand in the Asia-Pacific region will rise to 41 million barrels per day by 2050, up from 35 million barrels per day in 2024.

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New numbers show Canada’s oil and gas sector remains far ahead of other industries when it comes to environmental protection spending.

Statistics Canada reports that oil and gas producers and pipeline operators spent $4.3 billion on environmental protection in 2023 — the highest total among the 20 industries surveyed.

The figures capture spending on staff, services, machinery and equipment used to prevent pollution and restore damaged environments.

The investment by oil and gas producers and pipeline operators represents more than one third of total environmental protection spending in Canada. 

It’s more than triple the spend of the next-highest industry on the list, mining and quarrying, at $1.3 billion. Coming in third is primary metal manufacturing at $1.1 billion in 2023.  

From 2019 to 2023, oil and gas producers and pipeline operators spent $17.9 billion on environmental protection, more than primary metal manufacturers, miners and food manufacturers combined.

In 2023, across sectors businesses spent the most on wastewater management ($3.6 billion), followed by solid waste management ($2.6 billion) and air pollution management ($2.3 billion).  

In 2023, Alberta businesses accounted for the largest share of environmental protection spending at 39 per cent, followed by Ontario at 20 per cent.

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In the heart of the Canadian Shield, the Tenaris pipe mill in Sault Ste. Marie, Ont., has been running at record levels, thanks in large part to growing oil and gas production in Western Canada. 

In 2025, the factory reached its highest-ever output of seamless pipe in its 25-year history. 

And it’s on track to exceed that mark again in 2026, a milestone that reflects the company’s critical role in the steel town’s economy, as well as in Canada’s broader energy supply chain.

A worker checks steel pipe at the Tenaris manufacturing facility in Sault Ste. Marie, Ont. Photo courtesy Tenaris

Tenaris employs about 1,200 people nationwide, including roughly 800 in Sault Ste. Marie, manufacturing high-grade steel pipe that is shipped by rail to service centres in Alberta and British Columbia, where it supports oil and gas drilling and production.

“Our steel pipe manufacturing in the East allows oil and gas exploration to advance and flourish in the West,” says Jessica Tett, communications manager for Tenaris in Canada. 

“As the country strengthens its position as a global energy superpower, we are committed to powering that growth through our manufacturing, industrial expertise and support for Canada’s energy industry.”

As momentum builds around discussions of a new oil pipeline to Canada’s west coast, the country’s steel producers are sounding a clear, unified message: this isn’t just a project about energy transport — it’s a chance to strengthen Canada’s industrial core, support jobs and build supply chains that ensure national resilience.

Workers complete the “golden weld” signifying mechanical completion of the Trans Mountain Expansion project on April 11, 2024 in the Fraser Valley between Hope and Chilliwack, B.C. Photo courtesy Trans Mountain Corporation

Among other things, the recent energy agreement between Alberta and Canada to pursue a major new export pipeline to reach Asian markets commits both governments to develop Canadian steel and pipe production supply chains.

For steelmakers and manufacturers, the agreement signals a potential shift toward nation-building projects that prioritize Canadian materials, Canadian labour and Canadian expertise.

A cornerstone of Canada’s industrial economy

Tenaris’s experience reflects the broader importance of Canada’s steel industry, which is a cornerstone of the national economy and a critical supplier to energy, construction, transportation and manufacturing sectors. 

Tenaris employees work with pipe threading equipment at the company’s manufacturing facility in Sault Ste. Marie, Ont. Photo by Peter Power for the Canadian Energy Centre

Canada’s steel industry generates roughly $15 billion in annual output, directly employs about 23,000 people, and supports more than 100,000 additional jobs across related industries, according to the Canadian Steel Producers Association (CSPA).

Energy is one of the steel sector’s most important markets. 

The CSPA estimates oil and gas, wind towers and power generation together account for roughly 30 per cent of steel demand in Canada.

“We’re excited about it,” said François Desmarais, vice-president of trade and industry affairs at the CSPA, referring to the agreement and the prospect of a major new pipeline. 

“It’s a signal that we have an interest in the energy sector. It creates more certainty for our business.”

A worker looks on as crews build the Coastal GasLink pipeline in B.C. The project was completed in November 2023. Photo courtesy Coastal GasLink

Domestic supply in a volatile global market

Industry leaders say expanding Canadian energy infrastructure has become increasingly important as steel producers face mounting international trade pressures. 

The U.S. now charges a 50 per cent tariff on the first tonne of steel imported from any country, sweeping Canada into a broader move to deal with global steel oversupply.

“The net was too wide, and we got caught in it,” Desmarais said. 

“Many countries are trying to protect their national industries from surplus steel, particularly with China producing too much.”

Against that backdrop, building domestic demand through major energy projects could help offset lost export opportunities.

“We supply about 50 per cent of steel consumption in Canada,” Desmarais said. 

“There’s no reason why we can’t supply more.”

Steel pipe in storage for the Trans Mountain Expansion project in 2022. Photo courtesy Trans Mountain Corporation

Tenaris, which sells most of its Canadian-made production domestically, says it has less exposure to U.S. tariffs but strongly supports federal efforts to maintain a level playing field by countering unfairly traded imports.

“Made-in-Canada steel is critical to Canadian sovereignty in our energy supply chain,” Tett said.

Manufacturing ripple effects

The potential benefits of a west coast pipeline would extend well beyond steel mills. 

Canadian Manufacturers & Exporters (CME) says the energy agreement reflects a positive shift in how governments view Canada’s energy and industrial potential.

“Energy policy is manufacturing policy,” said Ryan Greer, CME’s senior vice-president of public affairs and national policy. 

“Canadian manufacturers will supply steel, fabricated metal, valves, pumps, electrical components, coatings, heavy equipment, control systems and more.”

An employee applies final adjustments on a new premium line at the Tenaris pipe manufacturing hub in Sault Ste. Marie, Ontario on October 31, 2022. Photo by Peter Power for Canadian Energy Centre

Greer said megaprojects have become increasingly important as Canadian manufacturers navigate tariff uncertainty and volatile trade relationships.

“While we hope Canada and the U.S. can get North American trade back on a more predictable trajectory, it has become clear that Canada must assertively try to generate jobs, growth and prosperity in ways that aren’t reliant on U.S. decision-making,” he said.

Becoming Canada’s own best customer

Steel producers say governments can maximize the economic benefits of a major pipeline by clearly identifying material needs early and prioritizing domestic procurement.

“Map out what the needs are or will be,” Desmarais said. “That allows companies to make the business case to retool if necessary.”

With billions already invested in Canadian facilities — including $255 million Tenaris has invested in Sault Ste. Marie, since 2020 — industry leaders say Canada is well-positioned to deliver.

The “Golden Weld” marked mechanical completion of the Trans Mountain Expansion project on April 11, 2024. Photo courtesy Trans Mountain Corporation

“Everybody is doing it — the U.S., Europe and others are looking out for their own industries,” Desmarais said. 

“Canada needs to do the same and become our own best customer.”

For companies like Tenaris, that approach would reinforce a truly national supply chain — one that starts in Ontario steel mills and ends at energy projects powering Canada’s economic future.

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A steady stream of more than 450 oil tankers calls at ports in Eastern and Atlantic Canada every year, drawing little public attention.

That’s in part due to the industry’s safety record in the region, where accidents involving tankers are rare. 

The most recent serious pollution incident from an oil tanker took place in Nova Scotia more than 45 years ago, and the last recorded minor spill from a tanker occurred 25 years ago, following a grounding incident in Labrador.

“Marine shipping as a whole is extraordinarily safe when you look at nautical miles travelled versus incidents,” said Meghan Mathieson, director of strategy and engagement for Clear Seas, an independent not-for-profit that studies marine shipping issues. 

“In Canada, shipping is much safer than your morning commute driving in a vehicle. Of the spills that do occur, most come from fuel from pleasure boats or fishing vessels,” she said. 

“People should not conflate debates about the pros and cons of fossil fuel production with marine safety. Is it safe to ship oil and gas in Canada? Yes, it is.”

Where tanker traffic occurs

Prior to the 2024 completion of the Trans Mountain expansion, about 85 per cent of oil tanker traffic in Canadian waters took place in Atlantic Canada, according to Clear Seas.

The increase in tanker traffic off the B.C. coast has shifted the overall balance to 58 per cent of movements on the West Coast and 42 per cent on the East Coast.

Map courtesy Clear Seas

In Atlantic Canada, this is divided between Saint John, NB, which sees about 115 tankers annually importing crude oil, and the Whiffen Head facility in Newfoundland, where 90 tankers are loaded for export every year.

There are also an estimated 240 shuttle tanker transits annually along the St. Lawrence Seaway in Quebec, moving oil between a storage facility in Montreal and a refining facility in Lévis.

Mathieson says there is greater familiarity with oil tankers in Atlantic Canada than in other areas. 

“They have been used to seeing tankers carry oil for a lot longer in that region. But there’s a cultural component as well. Wherever you are in Atlantic Canada, you are not that far from the ocean,” she said. 

“A lot more people work in the marine sector, such as fishing and offshore oil, than other parts of the country, or they know people who do. They are on the water more, so they may be more familiar with the advancements made by the industry to make it safer.”

How tanker safety has evolved

Many of those improvements came in the wake of the 1989 Exxon Valdez oil spill in Alaska’s Prince William Sound. 

Graph courtesy International Tanker Owners Pollution Federation

“Catastrophic incidents tend to stay in people’s minds when discussing marine safety, but so much has changed in the industry in terms of standards and procedures since then,” Mathieson said. 

“Today’s tankers are designed to be safer—they have double hulls and reinforced attachment points for towing equipment. And the procedures and protocols have advanced just as much, from having local pilots guide them into port to inspections by Transport Canada and certified response organizations for spill clean-up.” 

Spill response organizations on both coasts

Eastern Canada Response Corporation (ECRC) is responsible for responding to spills throughout Atlantic Canada as well as the Great Lakes, Quebec, and St. Lawrence Seaway. 

ECRC is the eastern counterpart to the Western Canada Marine Response Corporation (WCMRC), which is responsible for protecting all 27,000 kilometres of Canada’s western coastline. 

In anticipation of increased tanker traffic from the Trans Mountain expansion, WCMRC completed Canada’s largest-ever expansion of marine oil spill response capacity, doubling its capabilities with new vessels and response bases.

ECMRC’s area of response runs from the Alberta/B.C. border to offshore Newfoundland and from the U.S. border to the 60th parallel.  

Part of the marine community

“We have six response centres located throughout the area that face different challenges based on climate and other factors,” said Michael Kean, manager for the ECRC’s Dartmouth Response Centre, which covers parts of New Brunswick, Prince Edward Island and Nova Scotia as well as the Northumberland Strait and Cabot Strait shipping areas. 

“Some of those areas will ice over for parts of the year, as an example, while our region remains ice free. But regardless of the different challenges, we are training around the year so we are ready.”

The unaltered reproduction of this content is free of charge with attribution to the Canadian Energy Centre.

In the heart of Alberta’s oil sands region, a lake sits next to Suncor Energy’s Mildred Lake operation. 

On the surface, it looks like one of the countless natural lakes dotting the boreal forest north of Fort McMurray. But several metres below, it tells a different story. 

Base Mine Lake is not a natural lake—it’s a demonstration pit lake at one of the industry’s oldest mines. 

Once a tailings pond, Base Mine Lake was capped with water in 2012 and is now undergoing reclamation, drawing on decades of innovation to restore the land and water affected by development. 

Base Mine Lake. Photo courtesy Suncor Energy

“Tailings ponds aren’t meant to be a permanent part of our closure landscapes,” said Rodney Guest, Suncor’s senior development advisor, mine water closure. 

“We’re investing significant resources to advance tailings treatment technologies in support of land and aquatic reclamation to meet our commitments.”

Those commitments include fully reclaiming mine sites, including tailings facilities, and returning the land to Albertans and local communities, he said. 

Pit lakes: widely used around the world

Pit lakes are a common mine reclamation and closure practice used worldwide. 

According to the Canadian Association of Petroleum Producers (CAPP), a pit lake is basically any lake formed within a former mine pit. 

Over time, as the site stabilizes, these lakes generally come to look and function much like natural lakes. 

Thousands of examples exist globally, particularly in coal and hard-rock mining operations such as gold and copper, CAPP says.

Helping address oil sands tailings

Even as the oil sands sector has reduced its freshwater use per barrel by nearly one-third since 2013, the total volume of fluid tailings has reached about 1.4 billion cubic metres, reflecting continued production growth. 

Aquatic reclamation techniques like pit lakes are helping address the tailings challenge. 

This is evident in the reduction of “legacy tailings,” or tailings placed in storage before 2015. 

Since 2015, the volume of legacy tailings across Alberta’s oil sands has fallen by 40 per cent, according to Alberta Energy Regulator data. 

Base Mine Lake has contributed to this reduction, which overall is helped by water-capped tailings and permanent aquatic storage structure (PASS) technology.

How water-capped tailings technology works

Oil sands tailings are a mixture of fine clay, water, sand, and residual bitumen left over from the bitumen extraction process. 

Traditionally stored in large ponds, these liquid tailings settle very slowly—a process that can take decades. Water-capped tailings technology provides a more controlled solution.

In this approach, a layer of water is placed over tailings within a mined-out pit, forming a pit lake. 

The water cap isolates the tailings from the surface environment while promoting the development of a natural aquatic ecosystem.

Supported by long-term research

Numerous pit lakes, with and without tailings, are proposed or planned for the oil sands region. 

Each is designed to integrate into the final reclaimed landscape, supporting sustainable water management and creating new habitats for aquatic and terrestrial life.

Long-term research and monitoring at several sites—some dating back to the 1980s—has shown that water-capped tailings can be effective. 

Bacteria quickly break down many compounds within the tailings, while the solids settle naturally within weeks. The water layer above largely prevents tailings sediments from migrating back to the surface.

Base Mine Lake. Photo courtesy Pathways Alliance

Base Mine Lake performance

At Base Mine Lake, for example, a water cap currently between 10 and 13 metres covers the tailings. Ongoing research and monitoring show it’s performing as expected, Guest said.

“The tailings remain contained at the bottom and don’t mix with the water,” he said. 

“Water quality continues to improve, diverse habitats are forming, and typical boreal lake life including insects, invertebrates, plants and mammals are present in and around the demonstration watershed.”

While the lake doesn’t currently discharge to the environment, the long-term plan is for its water to eventually integrate into the regional watershed. 

Prior to release, water will be monitored and tested to ensure it meets regulated water quality guidelines, Guest said. 

In the meantime, Suncor adds fresh water and withdraws water for use in its mine operations. 

PASS technology demonstration

Suncor is implementing permanent aquatic storage structure (PASS) technology at a demonstration site that includes Lake Miwasin, a 10-metre-deep lake with a five-metre water cap. 

PASS uses common treatment agents to help tailings settle and release water more quickly. The process speeds up consolidation and helps improve overall water quality.

The company says early results are promising, showing expected improvements in water quality and the re-establishment of vegetation.

Insights from local Indigenous communities have helped refine techniques, including influencing landform design and identifying culturally important plants and trees.  

Confidence in pit lakes

“Results from Base Mine Lake and Lake Miwasin give us the confidence that pit lakes are a safe and integral component of our planned closure landscape,” Guest said.

The transition to a fully reclaimed boreal landscape in Alberta’s oil sands will take time. 

Most of the reclaimed area will consist of forests and wetlands, with pit lakes expected to account for less than 10 per cent. 

The unaltered reproduction of this content is free of charge with attribution to the Canadian Energy Centre.

*References to land that is reclaimed, permanently reclaimed and surface reclaimed meet the definition of “permanently reclaimed” as defined in the Alberta Energy Regulator Direction for Conservation and Reclamation Submissions (December 2018).