It’s a cool spring morning in northern Alberta, as Matthew Michetti watches clouds of warm breath rise from the small herd of bison as they circle close to one another out of an instinct for protection. 

Then an even more magical moment unfolds as a female moves toward the fenceline, watching closely as the calf she gave birth to just days ago follows on wobbly legs behind its mother. 

“It’s hard to put into words how powerful it is to see bison returned to this land after more than 100 years,” says Michetti, manager of government and industry relations for the Willow Lake Métis Nation, located about 400 kilometres northeast of Edmonton.

“Not only is our herd growing already, which is important for the future of our ranch, it is also an important symbol for the community as we become more self-sufficient and revive the culture that has been gone for so long.”

During a chilly February blizzard, 20 wood bison from Elk Island National Park were released into an enclosure on 82 hectares of land the Nation purchased in 2022 as the pillar of its long-term economic development and cultural renewal plan. 

From that milestone to the birth of the first calves and harvesting of the first crop of greenhouse-grown lettuce in May, the Nation’s ambitious sustainable farming initiative is quickly taking shape.

And as Michetti makes clear, the project’s success so far has been supported by critical partnerships with Alberta’s oil and gas industry.

From vision to reality

The roots of the Willow Lake Métis Farms project trace back to a pivotal moment for the Nation when it was able to acquire the historic homestead of a founding Métis family near Anzac, about 50 kilometres south of Fort McMurray. 

That acquisition was made possible through the Nation’s equity ownership in energy infrastructure projects including a share of Suncor Energy’s Northern Courier pipeline and a portion of seven Enbridge pipelines in the Athabasca region. The joint ventures are supported by the Alberta Indigenous Opportunities Corporation.

“Without those relationships, none of this could happen,” Michetti said.

It’s an approach that is gaining momentum across Canada. 

According to the Canada Energy Regulator, Indigenous communities now hold ownership interests in more than 5,000 kilometers of oil and gas pipelines, primarily in Alberta and B.C.

For Willow Lake Métis Nation, revenue generated through energy partnerships has become a cornerstone for long-term growth and development.

The land purchase set the stage for what has become a multi-phase project: a working bison ranch, a hydroponic “grow pod” producing fresh vegetables, and plans for expanded agriculture, traditional medicine cultivation and eventually an eco-tourism operation.

More than funding: building capacity

While financial backing was critical, Michetti emphasizes that the benefits of working alongside energy companies extend well beyond dollars.

Pipeline Systems and LNG Facilities with Indigenous Ownership

“These neighbours aren’t just financial partners,” he said. 

“They talk to us about how projects are developed. We’ve learned everything from engineering and design to permitting and execution. Our projects today are fully engineered, fully permitted—we’ve learned that approach from being around these developers.”

That transfer of knowledge has helped the Nation build internal capacity and confidence, transforming what began as an idea into a professionally managed, scalable operation.

“We’ve had to learn how to be bison ranchers, and now we also understand project development. We understand patience,” Michetti adds. “We’ve learned that from our neighbours in the energy industry.”

From leaseholders to neighbours

Today, many of those same companies are continuing their involvement. Not just as investors, but as active supporters and future customers of the farm.

As the Nation developed the project, it reached out to nearby energy operators for assistance. The response was strong, with more than $100,000 in cash and in-kind contributions provided.

But for Michetti, one example stands out.

“One of our closest neighbours, CNOOC (China National Offshore Oil Corp.), stepped up as our first sponsor,” he said. 

“They also told us they want to be our first customer once we begin commercial sales. That’s the difference between being a leaseholder and being a neighbour.”

Those future sales, supplying fresh produce to nearby industrial camps and communities, will help sustain the project financially, while reinforcing local supply chains in northern Alberta.

A sustainable, community-driven model

The bison ranch itself is intentionally modest in scale, designed to balance sustainability with cultural significance. The herd is expected to grow to about 30 to 35 animals, producing a limited annual harvest primarily for community use.

“This will never be a large commercial operation,” Michetti says. “It’s about food security for our people and the Nations around us, and about reconnecting with something that has deep meaning.”

Alongside the bison, the farm’s greenhouse is expected to produce roughly 10,000 pounds of fresh greens annually, with additional acreage dedicated to vegetables and traditional Indigenous plants.

The project is creating local employment and training opportunities, with roles ranging from ranching and farming to operations and education partnerships with nearby schools.

“It’s about creating a different kind of economy here,” Michetti explained. “One that’s local, sustainable and rooted in our community.”

A model for reconciliation and development

For the Willow Lake Métis Nation, the project represents more than economic diversification. It’s part of a broader vision of self-determination.

Over the past several years, the Nation has strengthened its governance, expanded its economic base and built partnerships that align with its long-term goals. The farm and ranch are tangible expressions of that progress.

Michetti believes the collaboration with the energy sector offers an important lesson.

“The industry gets painted with a lot of negative brushes,” he said. “But this is an example where they’re helping lead—where partnerships are built on respect, and where success comes from working together.”

Back at the farm, that collaboration is already bearing fruit, both literally and figuratively.

“It’s been a life-changing experience to be part of this,” Michetti said. “There are a lot of good things still to come. In a few years, this is going to be a very special place.”

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Alberta’s oil sands have emerged as one of North America’s most attractive oil plays as costs rise in competing basins like the Permian in Texas, according to a recent report. 

The oil sands hold 177 billion barrels of proved reserves, making it the largest play in North America by a wide margin.

Existing operations have some of the continent’s lowest production costs, said Trevor Rix, a director with Enverus Intelligence Research. 

“Operators have become more efficient and have tremendously low sustaining break-even costs, arguably the lowest in North America,” Rix said. 

“Some steam-assisted gravity drainage [SAGD] operations can break even at less than US$40 per barrel.”

Meanwhile, comparative costs in the Permian have risen toward US$65 per barrel, he said. 

Misunderstood economics

Kevin Birn, chief analyst for Canadian oil markets at S&P Global, said the oil sands sector’s economics have been poorly understood.

“The oil sands require upfront capital and time to bring on new facilities, so you need to be patient before your operations generate returns,” said Birn. 

“Once you pass that entry barrier, the oil sands are incredibly competitive in terms of sustaining costs. After that capital is sunk, the oil sands are a production machine compared to other conventional and unconventional plays.”

Unlike U.S. shale plays, oil sands production is long-life and low-decline, without the treadmill of ongoing investment in new wells.

Large oil sands reserves support mining projects that require no drilling, while the standard SAGD method involves about 60 per cent fewer wells than the average shale play, according to BMO Capital Markets.

Today’s lower oil sands costs come in part from improved drilling technologies, faster drill times and more precise well placement, Birn said.

Practices such as predictive maintenance on critical equipment have also reduced downtime and unplanned outages. 

“These plants are running harder and faster for longer periods of time,” Birn said.

“A lot of it is simply learning by doing.”

Heavy oil market tightening

The heavy oil produced in the oil sands is seeing strong demand as global heavy crude markets tighten.

Increased oil sands production has driven a nearly 800,000-barrel-per-day surge in Canada’s oil exports since 2021, according to Canada Energy Regulator data.

“The heavy oil segment of the [global] market is probably around nine to 10 million barrels per day, driven by refineries that have built special equipment to handle that around the world,” said Birn. 

Increased demand comes alongside continuing long-term declines in competing sources of supply, principally in Latin American producers such as Mexico and Venezuela, he said. 

“We’ve seen the heavy oil market actually tighten because more refineries are putting capacity towards processing heavier crudes around the world,” he said. 

“That increased demand has contributed to a better price for Canadian producers. And that’s before geopolitical considerations led to uncertainty around supply.”

Pipeline capacity

Enverus is calling for more pipeline infrastructure, projecting that oil sands production growth will fill current capacity in the next seven years.

“Given the historically long lead times for greenfield pipeline projects, we believe it is prudent to begin that planning and permitting process now,” analysts wrote. 

Given the rising demand for heavier crudes, Toronto-based energy analyst Rory Johnston sees several plausible options for increasing capacity to send barrels to customers in the United States and Asia.

This includes expansions and optimizations of the Enbridge Mainline, Trans Mountain system, South Bow’s proposed Prairie Connector, and the new West Coast Oil Pipeline proposed by Alberta’s government.  

“We’re in an interesting sweet spot right now in that we have competing egress options on the table for the first time since the heyday of TMX, Keystone XL and Energy East more than a decade ago,” said Johnston, publisher of the Commodity Context newsletter. 

“But we can never take this for granted as options can disappear at any moment. If we actually are coming to a place of choosing what’s the best option rather than what’s easiest to get over the line, that’s important.”

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A new forest will soon take root near Edmonton, creating a “green island” within Alberta’s Industrial Heartland.

Roughly the size of 50 Canadian football fields, the Keyera Legacy Forest is a partnership between pipeline operator Keyera, environmental nonprofit Project Forest and Strathcona County.

The partners call the project a rare, once-in-a-lifetime opportunity to responsibly restore designated industrial land.

“In this province, it can take 80 to 100 years for a forest to establish itself fully. But if you are driving past this site in 15 to 20 years, you’ll look over and see a forest and you won’t know it’s been planted,” said Project Forest founder and executive director Mike Toffan.

Not industrial reclamation

The Keyera Legacy Forest is not an industrial reclamation project, Toffan stressed.

“There is no legal responsibility or liability attached to this site or any sites we work on,” he said.

Project Forest partners with landowners or rights holders who want to bring back wilderness to local landscapes, Toffan said.

The projects are designed to be accessible to surrounding communities, allowing citizens to engage with natural spaces.

Between 2020 and 2024, the nonprofit reports planting 13 forests across more than 320 acres, with support from 72 funding partners.

“What’s critical for us as an organization is there is no greenwashing through our projects. We are not an oil and gas lobbyist, either,” Toffan said.

“We have corporate partners in many different sectors, including retail and banking, but we are proud of our partnerships with energy companies, too. The ones we work with, like Keyera, are amazing corporate citizens who care about doing the right thing.”

Building ecological value

Project Forest previously partnered with Keyera to plant 4,000 trees in the 32-hectare Camp Creek Conservation Area about 150 kilometres northeast of Edmonton, and the Wagner Natural Area, a 251-hectare protected area on the western outskirts of Alberta’s capital.

“The Wagner Natural Area has a high ecological importance,” Toffan said.

“There’s a fen with very rare orchids and plants and it is essential that those unique areas are preserved as urban environments grow.”

New forest planting to begin

Work on the Keyera Legacy Forest will start this fall, with more than 40,000 native trees and shrubs scheduled for planting in areas that did not naturally regenerate following a 2009 wildfire.

“The forest fire burned so hot that the seed source was destroyed in certain areas. And while the plants are coming back naturally in patches, it’s not coming back like it should be,” Toffan said.

“It’s a complicated project because there’s above and below ground infrastructure in the region.”

The team will plant native species, with balsam poplar and white birch accounting for the majority of trees along with white spruce and western mountain ash. There will also be bushes including pin cherry and western choke cherry.

Long-term community impact

The forest will be on land owned by Strathcona County, which used a conservation easement to protect the area.

Stephen Rausch, the municipality’s manager of investment attraction, said projects like this help build stronger ties with industrial operators that want to give back to the community.

“It reflects our desire to be the community of choice for new investments that have broad impacts to our residents and economy,” Rausch said.

Keyera is a major employer and landowner in the area, said Brandon Wood, Keyera’s director of external affairs.

The forest is an opportunity to deliver a lasting impact by supporting biodiversity in a region where the company has operated for more than 20 years, he said.

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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.

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