Growing up in a small town in central Alberta, Blake Wickland saw what oil and gas companies contributed to the community.

“They did so much in Drayton Valley – my minor hockey teams always had an energy or energy services company sponsor us — and I’m sure people who grew up in any small town in Alberta could say the same thing,” Wickland said.

He wound up working in the industry, building and maintaining facilities around the province and the globe in scorching summer heat and freezing January darkness for almost three decades.

“I’ve seen a lot of change in the industry in that time. Some developments are very exciting and what we are seeing with methane emissions is one of them,” Wickland said.

“We are doing important work by making a stronger oil and gas industry through emissions reduction. Doing that helps future proof our industry and all the benefits it brings.”

These days, Wickland serves as executive director of the Calgary-based Methane Emissions Leadership Alliance, but remains focused on work at the wellhead.

Emissions targets surpassed

In Alberta, producers met the target of reducing methane emissions in the province by 45 per cent below 2014 levels three years ahead of schedule in 2022 — and have since surpassed it, with a 51 per cent reduction in 2024.

Oil and gas producers in B.C. are also ahead of schedule, reducing methane emissions by 51 per cent as of 2023, beating the province’s 2025 target of 45 per cent two years early.

New technology funding

Late last year, the Alberta government announced nearly $30 million in technology funding to help further reduce methane emissions in the oil and gas sector.

Emissions Reduction Alberta (ERA) will receive $22.4 million for its new Methane Reduction Deployment Program, while $7 million was earmarked for the NGIF Accelerator’s new Methane Reduction Demonstration Program.

The funding comes from Alberta’s Technology Innovation and Emissions Reduction (TIER) program, financed by levies paid by oil and gas producers under the province’s carbon pricing system.

“Our goal is to reduce emissions intensity by 20 per cent per project on average,” said Luca Jungen, ERA’s efficiency program delivery lead.

“There’s a much greater warming potential with methane than CO2 so the more we do with methane, the easier it is for Alberta and the energy industry to hit their GHG targets.”

Deploying methane-cutting technologies

Calgary-based Spartan Controls is one of the companies whose technologies have helped slash methane emissions in Alberta.

Spartan manager of environmental solutions Brian Van Vliet said previous incentives have helped companies adopt technologies that cut methane emissions.

“Producers trying to run a business face challenges being competitive globally with variable commodity prices, constraints in access to market and differing regulatory requirements. Implementing technologies to cut methane emissions is an added capital cost,” Van Vliet said.

“Providing funding through TIER, which industry pays into, makes sense because industry can get some of those dollars back when they continue to invest in eligible measures  that reduce their GHG footprint. And that benefits industry and the province because Alberta is producing hydrocarbon products with lower carbon intensities.”

Exporting Alberta innovation

Van Vliet said the benefits could reach beyond Alberta, with companies able to export methane reduction technologies to other regions.

“If something works in Alberta with its wide range of ambient temperatures and process conditions, it will be robust enough to work anywhere in the world,” he said.

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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. 

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*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).

Growing up in Calgary, 22-year-old Max McGivern was naturally drawn to Canada’s energy industry.

Now a political science student at the University of Calgary, he’s motivated to contribute to the sector by helping build knowledge and pride among young Canadians.

“It’s the beating heart of Canada. We’re really lucky to have such a massive surplus of natural resources, and to have a mindset that we develop them responsibly,” McGivern said. 

“It is being handled by the previous generation right now, but there will come a time when it’s our turn. It will become ours, so we need to know how to manage it effectively.”

For the past two years, McGivern has worked as a summer student with Young Canadians for Resources, a national youth-led advocacy organization focused on Canada’s natural resource sectors and their role in the economy.

“You get exposed to the discussion of natural resources and you get to discuss with other like-minded people, or even with people who don’t fully agree with natural resources,” McGivern said.

“It’s been immensely positive, and it’s been pretty transformative.”

McGivern has learned that energy is about more than just what comes through an electrical outlet.

“I understand that different elements go into energy, rather than just, like, cool, my phone is charged,” he said.

“It’s more than just, drill a hole, get some oil.”

Recent polling shows that young Canadians are interested in growing the country’s energy sector.

A December Ipsos survey found that 82 per cent of those aged 18 to 34 believe Canada should prioritize expanding oil and gas exports to other countries.

“It’s our responsibility to develop it, to get it to our neighbors. And you know that we will see prosperity. It’s not a question of if, it’s a question of when,” McGivern said.

He believes the future will bring greater cooperation and a deeper recognition of the role energy from all sources plays for Canadians.

“The more people understand the importance of energy and the role of energy in our lives, the better,” McGivern said.

“I think there’ll be more energy projects. Not just things like LNG, but that might be more wind farms, more geothermal. Even just with time, there are more technological innovations, so we’ll figure out more ways to harness different energies.”

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For the first time in nearly eight years, a brand-new oil sands project is operating in Alberta.

It’s a rare development even as oil sands production continues to set new records.

That’s because Blackrod, located about 3.5 hours north of Edmonton, isn’t an expansion or optimization of an existing project. 

It’s a new facility built on a site that previously had no large-scale oil sands operations. 

Drilling for the Blackrod SAGD project. Photo courtesy International Petroleum Corporation

The 30,000-barrel-per-day steam-assisted gravity drainage (SAGD) project will be “transformational” for Vancouver-based International Petroleum Corporation (IPC), said CEO William Lundin. 

At full rates, Blackrod will nearly double the company’s current production of about 45,000 barrels per day. And it’s got room to grow. 

“We very much believe in future phase expansions,” Lundin told analysts last year. 

“Blackrod [is] a massive resource base where we have greater than one billion barrels of contingent resources.”

The same could be said of the broader oil sands, a 1.8-trillion-barrel resource base where most growth over the past decade has come from optimizing existing projects, according to S&P Global.

Nearly all future growth will come from optimizations too, analysts said in S&P Global’s latest oil sands outlook. 

These “learning-by-doing” investments to expand the vast existing asset base are expected to increase oil sands production by about 400,000 barrels per day by 2030.

While it’s uniquely new, Blackrod is also based on learning by doing. 

At the site is one of the oil sands industry’s longest-running SAGD pilot projects, a single well pair operation that has been running since 2011.

Blackrod SAGD pilot operations. Photo courtesy International Petroleum Corporation

Production averaged about 630 barrels per day in 2025, according to the Alberta Energy Regulator. 

In 2023, IPC gave the go-ahead to build the first phase of full operations at Blackrod, an investment of approximately $1.17 billion. 

The project has regulatory approval to produce up to 80,000 barrels per day. 

Steam injection is now underway, marking the start of the underground warm-up phase, with first oil expected by the end of September. 

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The coming year could mark a turning point for the expansion of Canada’s oil and gas sector as governments look to harness its resources to drive economic independence and prosperity.

Against a backdrop of steady drilling activity and continued production growth, new major export projects are expected to take significant steps forward. 

Here are five key developments to watch. 

5. Modest growth in drilling activity

Oil and gas drilling in central Alberta, fall 2025. Photo supplied to the Canadian Energy Centre

Oil and gas drilling in Western Canada is set for modest increases in 2026 amid flat oil price forecasts and softer natural gas prices, according to the Canadian Association of Energy Contractors (CAOEC).

CAOEC projects an average of 213 active drilling rigs, up from 201 in 2025. A total of 5,709 wells are expected to be drilled, an increase of just under three per cent.

This will be accompanied by an average of 458 active service rigs, up from 447 in 2025. 

The activity is expected to support 85,000 direct and indirect jobs over the year. 

“These aren’t abstract figures; they’re the heartbeat of Canada, the proof that our work isn’t just about extracting resources — it’s about giving Canadians a hopeful future,” said CAOEC CEO Mark Scholz.

4. New investment spurred by Alberta-Canada agreement

Oil sands workers in northern Alberta. Photo courtesy Pathways Alliance

The recent wide-ranging energy agreement between the Alberta and federal governments could unlock new investment in data centres, emissions-reduction technology and oil sands growth in 2026.

The deal is “formidable,” Edmonton-based Capital Power CEO Avik Dey told investors in December. 

“It allows us a pathway to building new natural gas-fired power generation in Alberta,” he said.

The company announced it is now negotiating an electricity supply agreement with an unnamed data centre developer in the province.

Policy think tank Clean Prosperity estimates the $130-per-tonne carbon credit price agreed to by Alberta and Ottawa could unlock more than $90 billion in low-carbon investment including carbon capture and storage (CCS).

And as details of Alberta’s proposed pipeline to the northwest coast become clearer, oil sands producers could begin dusting off expansion plans.

According to BMO Capital Markets, producers have already submitted project proposals with combined capacity of 4.1 million barrels per day — enough to more than double current oil sands production.

This total includes both approved projects and proposals that are currently on hold or delayed.

3. Data centres taking flight

Alberta’s goal of attracting $100 billion in data centre investment is expected to advance in 2026 as key policy measures take shape and new projects receive approval.

Interest is strong, with proposed data centres now requesting more than 20 gigawatts of power, according to the Alberta Electric System Operator. 

The province passed legislation in 2025 that encourages data centres to bring their own generation to support their connection to the power grid. This is designed to enhance reliability of the grid while accelerating the approval process for data centre projects.

In December, two European companies announced a $1.26 billion plan to build four new AI-ready data centres in Alberta. 

Portugal-based Technologies New Energy will supply 80 per cent of the power for the new data centres for Data District Inc., a division of Swiss asset management firm Alcral AG. 

“Alberta offers the energy resources, industrial base and investment momentum to support this growth,” TNE said in a statement.

Initial operations are targeted for 2026.

2. Go-ahead for Ksi Lisims LNG

Rendering of the proposed Ksi Lisims LNG project. Image courtesy Ksi Lisims LNG

An Indigenous-led floating LNG terminal on B.C.’s northern coast near Alaska is “not far off” from a final decision to proceed. 

That milestone is expected in 2026, spokeswoman Rebecca Scott said in November. 

Ksi Lisims (pronounced “s’lisims”) is a partnership between the Nisga’a Nation, a consortium of Canadian natural gas producers called Rockies LNG, and a subsidiary of Houston-based Western LNG. 

The 12-million-tonne-per-year project would help significantly expand Canada’s LNG export capacity, which is currently about 14 million tonnes per year. 

In November, Ksi Lisims was referred for fast-tracking by Canada’s new Major Projects Office (MPO). 

Start-up is targeted for 2029.   

1. Advancing a new northwest coast oil pipeline

Pipe in storage for the Trans Mountain expansion near Hope, B.C. in August 2019. CP Images photo

Alberta’s application to the MPO for a new oil pipeline to the northwest coast is expected by July 1, 2026. 

It’s a project that’s been designated in the national interest as a key measure to establish Canada as an energy superpower.

The pipeline application is expected to target a deep-water port for oil exports to Asian markets, while creating opportunities for Indigenous ownership. 

If a proposal is approved, the federal government has committed to enabling bitumen exports, including an “appropriate adjustment” of the tanker moratorium on B.C.’s north coast if necessary. 

The governments have also agreed to a maximum two-year timeframe for permitting and approvals.

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Canada’s energy landscape changed significantly in 2025, with mounting U.S. economic pressures reinforcing the central role oil and gas can play in safeguarding the country’s independence.

Here are the Canadian Energy Centre’s top five most-viewed stories of the year.

5. Alberta’s massive oil and gas reserves keep growing – here’s why

The Northern Lights, aurora borealis, make an appearance over pumpjacks near Cremona, Alta., Thursday, Oct. 10, 2024. CP Images photo

Analysis commissioned this spring by the Alberta Energy Regulator increased the province’s natural gas reserves by more than 400 per cent, bumping Canada into the global top 10.

Even with record production, Alberta’s oil reserves – already fourth in the world – also increased by seven billion barrels.

According to McDaniel & Associates, which conducted the report, these reserves are likely to become increasingly important as global demand continues to rise and there is limited production growth from other sources, including the United States.

4. Canada’s pipeline builders ready to get to work

Photo courtesy Coastal GasLink

Canada could be on the cusp of a “golden age” for building major energy projects, said Kevin O’Donnell, executive director of the Mississauga, Ont.-based Pipe Line Contractors Association of Canada.

That eagerness is shared by the Edmonton-based Progressive Contractors Association of Canada (PCA), which launched a “Let’s Get Building” advocacy campaign urging all Canadian politicians to focus on getting major projects built.

“The sooner these nation-building projects get underway, the sooner Canadians reap the rewards through new trading partnerships, good jobs and a more stable economy,” said PCA chief executive Paul de Jong. 

3. New Canadian oil and gas pipelines a $38 billion missed opportunity, says Montreal Economic Institute

Steel pipe in storage for the Trans Mountain Pipeline expansion in 2022. Photo courtesy Trans Mountain Corporation

In March, a report by the Montreal Economic Institute (MEI) underscored the economic opportunity of Canada building new pipeline export capacity.

MEI found that if the proposed Energy East and Gazoduq/GNL Quebec projects had been built, Canada would have been able to export $38 billion worth of oil and gas to non-U.S. destinations in 2024.

“We would be able to have more prosperity for Canada, more revenue for governments because they collect royalties that go to government programs,” said MEI senior policy analyst Gabriel Giguère. 

“I believe everybody’s winning with these kinds of infrastructure projects.”

2. Keyera ‘Canadianizes’ natural gas liquids with $5.15 billion acquisition

Keyera Corp.’s natural gas liquids facilities in Fort Saskatchewan, Alta. Photo courtesy Keyera Corp.

In June, Keyera Corp. announced a $5.15 billion deal to acquire the majority of Plains American Pipelines LLP’s Canadian natural gas liquids (NGL) business, creating a cross-Canada NGL corridor that includes a storage hub in Sarnia, Ontario. 

The acquisition will connect NGLs from the growing Montney and Duvernay plays in Alberta and B.C. to markets in central Canada and the eastern U.S. seaboard.

“Having a Canadian source for natural gas would be our preference,” said Sarnia mayor Mike Bradley. 

“We see Keyera’s acquisition as strengthening our region as an energy hub.” 

1. Explained: Why Canadian oil is so important to the United States

Enbridge’s Cheecham Terminal near Fort McMurray, Alberta is a key oil storage hub that moves light and heavy crude along the Enbridge network. Photo courtesy Enbridge

The United States has become the world’s largest oil producer, but its reliance on oil imports from Canada has never been higher.

Many refineries in the United States are specifically designed to process heavy oil, primarily in the U.S. Midwest and U.S. Gulf Coast.

According to the Alberta Petroleum Marketing Commission, the top five U.S. refineries running the most Alberta crude are:

• Marathon Petroleum, Robinson, Illinois (100% Alberta crude)
• Exxon Mobil, Joliet, Illinois (96% Alberta crude)
• CHS Inc., Laurel, Montana (95% Alberta crude)
• Phillips 66, Billings, Montana (92% Alberta crude)
• Citgo, Lemont, Illinois (78% Alberta crude)

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Indigenous communities across British Columbia are playing a critical role in building the foundation for LNG—from natural gas supply to pipeline corridors and export terminals—helping drive momentum as Canada’s LNG export sector takes its first steps.

A growing role for McLeod Lake Indian Band

One of these communities is the McLeod Lake Indian Band. Part of the Tse’khene group of Aboriginal peoples, McLeod Lake is located about 150 kilometres north of Prince George in the Montney natural gas region.

“McLeod Lake Indian Band wants to create a business environment within its traditional territory that is conducive to the responsible development of the area’s natural resources,” said Jacob Albertson, CEO of the Duz Cho Group of Companies, which is 100 per cent owned by the band.

Jacob Albertson, CEO of Duz Cho Group of Companies.

Since 2018, the bustling business has seen revenues surge nearly tenfold, from $14.5 million to $134 million annually.

‘Canadian gas is Indigenous gas’

Albertson recently joined the board of the First Nations Natural Gas Alliance (formerly the First Nations LNG Alliance), which has member organizations from B.C., Alberta and Newfoundland and Labrador.

“Canadian natural gas is Indigenous natural gas,” said Alliance CEO Karen Ogen, who served as elected Chief of the Wet’suwet’en First Nation from 2010 to 2016.

Ogen’s goal is to inspire and support more First Nations engaging in discussions with industry and government about potential resource opportunities.

Karen Ogen, CEO of the First Nations Natural Gas Alliance.

“We can show the world that Canada’s natural gas can be developed responsibly and advance economic reconciliation for the benefit of our citizens and those around the world who need an alternative to coal,” she said.

The Alliance’s work helped advance the Coastal GasLink pipeline, which is now delivering natural gas from northeast B.C. to the LNG Canada terminal at Kitimat, in the traditional territory of the Haisla Nation. 

“Attitudes have changed as knowledge has improved,” Albertson said. 

“That’s why I’m excited about the future and how the people of this region can benefit from it.”

A bigger voice for First Nations in B.C.’s interior

McLeod Lake was one of 20 Indigenous bands along the route whose elected leadership signed agreements with the pipeline project. 

Albertson sees joining the Alliance’s board as a chance to amplify the voice of B.C.’s interior Nations like McLeod Lake, whose traditional territories host much of the natural gas that feeds coastal LNG exports.

It’s important for community members to understand both the impacts and benefits of development, he said.

Business transparency helps builds support

To keep members better informed about local projects, Albertson began sharing Duz Cho’s monthly reports with the band’s 550 members, along with quarterly meetings in Prince George, Vancouver and Calgary.

“That transparency is very important,” Albertson said. 

“We’ve really focused on reporting about the benefits of these projects as well as the impacts. It’s helped the membership realize these projects are good for the community.”

Duz Cho now seeks job creation opportunities and equity partnerships rather than simply collecting royalties from industry.

“We restructured some of the agreements so members would have those opportunities,” says Albertson.

“There is a real value to hiring community members, who have firsthand knowledge of the projects they work on and can share that within the community.”

Duz Cho sign in Chetwynd, B.C. Photograph for Canadian Energy Centre

Education key to energy expansion in B.C. 

Improving understanding of resource projects is critical as Canada looks to expand its energy exports through B.C., Ogen said. 

“Those types of education and awareness need to happen, not only for LNG, but for oil,” she said. 

“I think that the process that we did helped us inform a lot of people.”

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Investor interest in Canadian oil producers, primarily in the Alberta oil sands, has picked up, and not only because of expanded export capacity from the Trans Mountain pipeline.

Enverus Intelligence Research says the real draw — and a major factor behind oil sands equities outperforming U.S. peers by about 40 per cent since January 2024 — is the resource Trans Mountain helps unlock.

Alberta’s oil sands contain 167 billion barrels of reserves, nearly four times the volume in the United States.

Today’s oil sands operators hold more than twice the available high-quality resources compared to U.S. shale producers, Enverus reports.

“It’s a huge number — 167 billion barrels — when Alberta only produces about three million barrels a day right now,” said Mike Verney, executive vice-president at McDaniel & Associates, which earlier this year updated the province’s oil and gas reserves on behalf of the Alberta Energy Regulator.

Already fourth in the world, the assessment found Alberta’s oil reserves increased by seven billion barrels.

Verney said the rise in reserves despite record production is in part a result of improved processes and technology.  

“Oil sands companies can produce for decades at the same economic threshold as they do today. That’s a great place to be,” said Michael Berger, a senior analyst with Enverus.

BMO Capital Markets estimates that Alberta’s oil sands reserves could maintain current production rates for more than 140 years. 

The long-term picture looks different south of the border. 

The U.S. Energy Information Administration projects that American production will peak before 2030 and enter a long period of decline. 

Having a lasting stable source of supply is important as world oil demand is expected to remain strong for decades to come.

This is particularly true in Asia, the target market for oil exports off Canada’s West Coast. 

The International Energy Agency (IEA) projects oil demand in the Asia-Pacific region will from 35 million barrels per day in 2024 to 41 million barrels per day in 2050. 

The growing appeal of Alberta oil in Asian markets shows up not only in expanded Trans Mountain shipments, but also in Canadian crude being “re-exported” from U.S. Gulf Coast terminals.

According to RBN Energy, Asian buyers – primarily in China – are now the main non-U.S. buyers from Trans Mountain, while India dominates purchases of re-exports from the U.S. Gulf Coast. .  

BMO said the oil sands offers advantages both in steady supply and lower overall environmental impacts. 

“Not only is the resulting stability ideally suited to backfill anticipated declines in world oil supply, but the long-term physical footprint may also be meaningfully lower given large-scale concentrated emissions, high water recycling rates and low well declines,” BMO analysts said. 

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For Canada, the path to a stronger economy — and stronger global influence — runs through energy. 

That’s the view of David Detomasi, a professor at the Smith School of Business at Queen’s University. 

Detomasi, author of Profits and Power: Navigating the Politics and Geopolitics of Oil, argues that there is a moral case for developing Canada’s energy, both for Canadians and the world. 

David Detomasi. Photo courtesy Smith School of Business, Queen’s University

CEC: What does being an energy superpower mean to you?

DD: It means Canada is strong enough to affect the system as a whole by its choices. 

There is something really valuable about Canada’s — and Alberta’s — way of producing carbon energy that goes beyond just the monetary rewards.

CEC: You talk about the moral case for developing Canada’s energy. What do you mean? 

DD: I think the default assumption in public rhetoric is that the environmental movement is the only voice speaking for the moral betterment of the world. That needs to be challenged.

That public rhetoric is that the act of cultivating a powerful, effective economic engine is somehow wrong or bad, and that efforts to create wealth are somehow morally tainted.

I think that’s dead wrong. Economic growth is morally good, and we should foster it. 

Economic growth generates money, and you can’t do anything you want to do in social expenditures without that engine. 

Economic growth is critical to doing all the other things we want to do as Canadians, like having a publicly funded health care system or providing transfer payments to less well-off provinces.

Over the last 10 years, many people in Canada came to equate moral leadership with getting off of oil and gas as quickly as possible. I think that is a mistake, and far too narrow. 

Instead, I think moral leadership means you play that game, you play it well, and you do it in our interest, in the Canadian way. 

We need a solid base of economic prosperity in this country first, and then we can help others.

CEC: Why is it important to expand Canada’s energy trade?

DD: Canada is, and has always been, a trading nation, because we’ve got a lot of geography and not that many people. 

If we don’t trade what we have with the outside world, we aren’t going to be able to develop economically, because we don’t have the internal size and capacity.

Historically, most of that trade has been with the United States. Geography and history mean it will always be our primary trade partner.

But the United States clearly can be an unreliable partner. Free and open trade matters more to Canada than it does to the U.S. Indeed, a big chunk of the American people is skeptical of participating in a global trading system. 

As the United States perhaps withdraws from the international trading and investment system, there’s room for Canada to reinforce it in places where we can use our resource advantages to build new, stronger relationships. 

One of these is Europe, which still imports a lot of gas. We can also build positive relationships with the enormous emerging markets of China and India, both of whom want and will need enormous supplies of energy for many decades.

I would like to be able to offer partners the alternative option of buying Canadian energy so that they are less reliant on, say, Iranian or Russian energy.

Canada can also maybe eventually help the two billion people in the world currently without energy access.

CEC: What benefits could Canadians gain by becoming an energy superpower? 

DD: The first and primary responsibility of our federal government is to look after Canada. At the end of the day, the goal is to improve Canada’s welfare and enhance its sovereignty. 

More carbon energy development helps Canada. We have massive debt, an investment crisis and productivity problems that we’ve been talking about forever. Economic and job growth are weak.

Solving these will require profitable and productive industries. We don’t have so many economic strengths in this country that we can voluntarily ignore or constrain one of our biggest industries. 

The economic benefits pay for things that make you stronger as a country. 

They make you more resilient on the social welfare front and make increasing defence expenditures, which we sorely need, more affordable. It allows us to manage the debt that we’re running up, and supports deals for Canada’s Indigenous peoples. 

CEC: Are there specific projects that you advocate for to make Canada an energy superpower?

DD: Canada’s energy needs egress, and getting it out to places other than the United States. That means more transport and port facilities to Canada’s coasts.

We also need domestic energy transport networks. People don’t know this, but a big chunk of Ontario’s oil supply runs through Michigan, posing a latent security risk to Ontario’s energy security. 

We need to change the perception that pipelines are evil. There’s a spiderweb of them across the globe, and more are being built.

Building pipelines here, with Canadian technology and know-how, builds our competitiveness and enhances our sovereignty. 

Economic growth enhances sovereignty and provides the resources to do other things. We should applaud and encourage it, and the carbon energy sector can lead the way. 

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The Trans Mountain system continues its decades-long record of zero marine spills even as oil tanker traffic has surged more than 800 per cent since the pipeline’s expansion in May 2024.

The number of tankers calling at Trans Mountain’s Westridge Marine Terminal in the Port of Vancouver in one month now rivals the number that used to go through in one year. 

A global trend toward safer tanker operations

The Westridge Marine Terminal loaded its first oil tanker shipment on January 1, 1956.

Nearly 70 years and a major expansion later, Trans Mountain’s ongoing safe marine operations are part of a worldwide trend.

Global oil tanker traffic is up, yet marine spills are down, according to the International Tanker Owners Pollution Federation, a London, UK-based nonprofit that provides data and response support.

Transport Canada reports a 95 per cent drop in ship-source oil spills and spill volumes since the 1970s, driven by stronger ship design, improved response and better regulations.

Graph courtesy International Tanker Owners Pollution Federation

“Tankers are now designed much more safely. They are double-hulled and compartmentalized to mitigate spills,” said Mike Lowry, spokesperson for the Western Canada Marine Response Corporation (WCMRC). 

WCMRC: Ready to protect the West Coast

One of WCMRC’s new response vessels arrives in Barkley Sound. Photo courtesy Western Canada Marine Response Corporation

From eight marine bases including Vancouver and Prince Rupert, WCMRC stands at the ready to protect all 27,000 kilometres of Canada’s western coastline. 

Lowry sees the corporation as similar to firefighters — training to respond to an event they hope they never have to see. 

In September, it conducted a large-scale training exercise for a worst-case spill scenario. This included the KJ Gardner — Canada’s largest spill response vessel and a part of WCMRC’s fleet since 2024.

“It’s part of the work we do to make sure everybody is trained and prepared to use our assets just in case,” Lowry said. 

Expanding capacity for Trans Mountain

The K.J. Gardner is the largest-ever spill response vessel in Canada. Photo courtesy Western Canada Marine Response Corporation

WCMRC’s fleet and capabilities were doubled with a $170-million expansion to support the Trans Mountain project. 

Between 2012 and 2024, the company grew from 13 people and $12 million in assets to more than 200 people and $213 million in assets. 

“About 80 per cent of our employees are mariners who work as deckhands, captains and marine engineers on our vessels,” Lowry said. 

“Most of the incidents we respond to are small marine diesel spills — the last one was a fuel leak from a forest logging vessel near Nanaimo — so we have deployed our fleet in other ways.” 

Tanker safety starts with strong rules and local expertise

Tanker loading at the Westridge Marine Terminal in the Port of Vancouver. Photo courtesy Trans Mountain Corporation

Speaking on the ARC Energy Ideas podcast, Trans Mountain CEO Mark Maki said tanker safety starts with strong regulations, including the use of local pilots to guide vessels into the harbour.

“On the Mississippi River, you have Mississippi River pilots because they know how the river behaves. Same thing would apply here in Vancouver Harbour. Tides are strong, so people who are familiar with the harbor and have years and decades of experience are making sure the ships go in and out safely,” Maki said. 

“A high standard is applied to any ship that calls, and our facility has to meet very strict requirements. And we have rejected ships, just said, ‘Nope, that one doesn’t fit the bill.’ A ship calling on our facilities is very, very carefully looked at.”

Working with communities to protect sensitive areas

Trans Mountain’s Westridge Marine Terminal at Burnaby, B.C. Photo courtesy Trans Mountain Corporation

Beyond escorting ships and preparing for spills, WCMRC partners with coastal communities to map sensitive areas that need rapid protection including salmon streams, clam beds and culturally important sites like burial grounds.

“We want to empower communities and nations to be more prepared and involved,” Lowry said. 

“They can help us identify and protect the areas that they value or view as sensitive by working with our mapping people to identify those areas in advance. If we know where those are ahead of time, we can develop a protection strategy for them.”

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