If you’ve ever been to an event at Rogers Place in Edmonton, you probably noticed the massive exposed concrete walls and columns that give the arena its unmistakable sense of strength. 

That strength is real — because like many buildings, bridges, roads, industrial projects and even sidewalks in Western Canada, Rogers Place is built from limestone quarried in the foothills of the Rocky Mountains.

Located about 350 kilometers west of Edmonton, the hamlet of Cadomin, Alta. has just 54 permanent residents, many of whom have mining in their blood. 

At the community’s edge is Heidelberg Materials Canada’s Cadomin Limestone Quarry. 

Connected by rail to the company’s Edmonton cement plant, each year the quarry delivers enough limestone to build 100 25-storey buildings or pave a 1,600-kilometre highway. 

“Our daily life in the western provinces – Alberta, Saskatchewan, Manitoba and northeast British Columbia – is built by concrete that is made from limestone supplied by the quarry,” said Joerg Nixdorf, Heidelberg Materials’ vice-president of cement operations. 

Heidelberg Materials is changing the way it mines limestone at the quarry, resulting in a reduced environmental footprint and continued safe access to decades of limestone reserves.

From the quarry to your door

Second only to water, concrete is the most widely used building material on Earth. Versions of it have shaped construction for thousands of years.

A familiar material all around us, concrete is made by mixing water with materials like sand and gravel and adding cement.

Cement, the “glue” that holds the concrete together, is a fine powder made from limestone – like that from the Heidelberg Materials Cadomin Quarry – along with other materials that contain silica, alumina and iron. 

Worldwide cement demand continues to rise. The International Energy Agency projects global cement demand will rise to 4.36 billion tonnes by 2050, about 10 per cent above 2024 levels. 

“It’s exciting to be a part of an industry that provides a material that literally builds everything,” said David Perkins, Heidelberg Materials’ senior vice-president of sustainability and public affairs. 

“You can create almost any kind of shape that you want, and then once you place that shape, it’s extremely resilient. It’s 100 per cent recyclable, it’s fire resistant and it’s extremely long-lasting.” 

Decades of operations

Originally known for coal mining, limestone mining is now Cadomin’s main industry.

Inland Cement Company (a predecessor to Heidelberg Materials) began quarrying limestone at this site in 1954.

For decades, this has been done by blasting, slowly moving equipment down the surface of the quarry.

The quarried limestone is conveyed through an inclined chute underground, where it is crushed and stored before being transferred to rail cars to be shipped to the Edmonton cement plant.

The quarry reached a point where operators faced a choice: relocate all the equipment and continue working on the surface — an expensive and highly impactful undertaking — or move the entire operation underground.

Moving underground

They chose the latter, and the limestone quarry is now in the process of being converted from a surface mine to the first fully underground limestone mine in Alberta. 

“The transition will help lower our environmental footprint by minimizing surface impacts, reducing the potential for dust and noise, and eliminating the need for large amounts of caprock removal, all while ensuring continued access to high-quality limestone,” said Brent Korobanik, permitting and community liaison for Heidelberg Materials in Edmonton.   

“From an economic perspective, it helps us out, but the big reason is sustainability.”

High-tech underground fleet

Moving underground allows Heidelberg Materials to retain existing infrastructure such as crushing equipment. It will also require a new mining fleet, supplied in part by Stockholm, Sweden–based Sandvik Group.

Sandvik says the fleet uses next-generation automation, and the project “could redefine expectations for how underground mining is executed in Canada.”

Heidelberg Materials expects the underground mine to be fully operational by spring 2027, when surface mining will be discontinued.

Sustainable Cement 

As Heidelberg Materials works to reduce its footprint at Cadomin, its Edmonton cement plant is advancing new sustainability strategies.

In 2025, the plant hit a major milestone, with 50 per cent of its fuel now coming from low-carbon alternative sources including processed municipal waste, demolition wood chips and tire fibre.

The project received provincial support, including a $2.4 million investment from Emissions Reduction Alberta.

The Edmonton cement plant also repurposes byproduct streams from other industries to replace traditional clay, ash, sand and iron in cement production.

This diverts waste from landfills and helps preserve Alberta’s natural resources.

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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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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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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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Tucked into the north coast of B.C. is the deepest natural harbour in North America and the port with the shortest travel times to Asia.

With growing capacity for exports including agricultural products, lumber, plastic pellets, propane and butane, it’s no wonder the Port of Prince Rupert often comes up as a potential new global gateway for oil from Alberta, said CEO Shaun Stevenson. 

Thanks to its location and natural advantages, the port can efficiently move a wide range of commodities, he said.

That could include oil, if not for the federal tanker ban in northern B.C.’s coastal waters.

The Port of Prince Rupert on the north coast of British Columbia. Photo courtesy Prince Rupert Port Authority

“Notwithstanding the moratorium that was put in place, when you look at the attributes of the Port of Prince Rupert, there’s arguably no safer place in Canada to do it,” Stevenson said. 

“I think that speaks to the need to build trust and confidence that it can be done safely, with protection of environmental risks. You can’t talk about the economic opportunity before you address safety and environmental protection.”

Safe Transit at Prince Rupert

About a 16-hour drive from Vancouver, the Port of Prince Rupert’s terminals are one to two sailing days closer to Asia than other West Coast ports.

The entrance to the inner harbour is wider than the length of three Canadian football fields. 

The water is 35 metres deep — about the height of a 10-storey building — compared to 22 metres at Los Angeles and 16 metres at Seattle. 

Shipmasters spend two hours navigating into the port with local pilot guides, compared to four hours at Vancouver and eight at Seattle. 

“We’ve got wide open, very simple shipping lanes. It’s not moving through complex navigational channels into the site,” Stevenson said. 

A Port on the Rise

The Prince Rupert Port Authority says it has entered a new era of expansion, strengthening Canada’s economic security.

The port estimates it anchors about $60 billion of Canada’s annual global trade today. Even without adding oil exports, Stevenson said that figure could grow to $100 billion.

“We need better access to the huge and growing Asian market,” said Heather Exner-Pirot, director of energy, natural resources and environment at the Macdonald-Laurier Institute. 

“Prince Rupert seems purpose-built for that.”

Roughly $3 billion in new infrastructure is already taking shape, including the $750 million rail-to-container CANXPORT transloading complex for bulk commodities like specialty agricultural products, lumber and plastic pellets.

The Ridley Island Propane Export Terminal, Canada’s first marine propane export terminal, started shipping in May 2019. Photo courtesy AltaGas Ltd.

Canadian Propane Goes Global

A centrepiece of new development is the $1.35-billion Ridley Energy Export Facility — the port’s third propane terminal since 2019.

“Prince Rupert is already emerging as a globally significant gateway for propane exports to Asia,” Exner-Pirot said. 

Thanks to shipments from Prince Rupert, Canadian propane – primarily from Alberta – has gone global, no longer confined to U.S. markets.

More than 45 per cent of Canada’s propane exports now reach destinations outside the United States, according to the Canada Energy Regulator. 

“Twenty-five per cent of Japan’s propane imports come through Prince Rupert, and just shy of 15 per cent of Korea’s imports. It’s created a lift on every barrel produced in Western Canada,” Stevenson said.

“When we look at natural gas liquids, propane and butane, we think there’s an opportunity for Canada via Prince Rupert becoming the trading benchmark for the Asia-Pacific region.” 

That would give Canadian production an enduring competitive advantage when serving key markets in Asia, he said. 

Deep Connection to Alberta

The Port of Prince Rupert has been a key export hub for Alberta commodities for more than four decades.

Through the Alberta Heritage Savings Trust Fund, the province invested $134 million — roughly half the total cost — to build the Prince Rupert Grain Terminal, which opened in 1985.

The largest grain terminal on the West Coast, it primarily handles wheat, barley, and canola from the prairies.

The Prince Rupert Grain Terminal. Photo courtesy Prince Rupert Port Authority

Today, the connection to Alberta remains strong. 

In 2022, $3.8 billion worth of Alberta exports — mainly propane, agricultural products and wood pulp — were shipped through the Port of Prince Rupert, according to the province’s Ministry of Transportation and Economic Corridors.

In 2024, Alberta awarded a $250,000 grant to the Prince Rupert Port Authority to lead discussions on expanding transportation links with the province’s Industrial Heartland region near Edmonton.

Handling Some of the World’s Biggest Vessels

The Port of Prince Rupert could safely handle oil tankers, including Very Large Crude Carriers (VLCCs), Stevenson said. 

“We would have the capacity both in water depth and access and egress to the port that could handle Aframax, Suezmax and even VLCCs,” he said.

“We don’t have terminal capacity to handle oil at this point, but there’s certainly terminal capacities within the port complex that could be either expanded or diversified in their capability.”

Market Access Lessons From TMX

Like propane, Canada’s oil exports have gained traction in Asia, thanks to the expanded Trans Mountain pipeline and the Westridge Marine Terminal near Vancouver — about 1,600 kilometres south of Prince Rupert, where there is no oil tanker ban.

The Trans Mountain expansion project included the largest expansion of ocean oil spill response in Canadian history, doubling capacity of the West Coast Marine Response Corporation.

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

The Canada Energy Regulator (CER) reports that Canadian oil exports to Asia more than tripled after the expanded pipeline and terminal went into service in May 2024. 

As a result, the price for Canadian oil has gone up. 

The gap between Western Canadian Select (WCS) and West Texas Intermediate (WTI) has narrowed to about $12 per barrel this year, compared to $19 per barrel in 2023, according to GLJ Petroleum Consultants. 

Each additional dollar earned per barrel adds about $280 million in annual government royalties and tax revenues, according to economist Peter Tertzakian. 

The Road Ahead

There are likely several potential sites for a new West Coast oil terminal, Stevenson said.

“A pipeline is going to find its way to tidewater based upon the safest and most efficient route,” he said. 

“The terminal part is relatively straightforward, whether it’s in Prince Rupert or somewhere else.”

Under Canada’s Marine Act, the Port of Prince Rupert’s mandate is to enable trade, Stevenson said. 

“If Canada’s trade objectives include moving oil off the West Coast, we’re here to enable it, presuming that the project has a mandate,” he said. 

“If we see the basis of a project like this, we would ensure that it’s done to the best possible standard.”

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A “weird and wonderful” drilling innovation in Alberta is helping producers tap more oil and gas at lower cost and with less environmental impact.

With names like fishbone, fan, comb-over and stingray, “multilateral” wells turn a single wellbore from the surface into multiple horizontal legs underground.

“They do look spectacular, and they are making quite a bit of money for small companies, so there’s a lot of interest from investors,” said Calin Dragoie, vice-president of geoscience with Calgary-based Chinook Consulting Services. 

Dragoie, who has extensively studied the use of multilateral wells, said the technology takes horizontal drilling — which itself revolutionized oil and gas production — to the next level.

“It’s something that was not invented in Canada, but was perfected here. And it’s something that I think in the next few years will be exported as a technology to other parts of the world,” he said. 

Dragoie’s research found that in 2015 less than 10 per cent of metres drilled in Western Canada came from multilateral wells. By last year, that share had climbed to nearly 60 per cent.  

Royalty incentives in Alberta have accelerated the trend, and Saskatchewan has introduced similar policy.

Multilaterals first emerged alongside horizontal drilling in the late 1990s and early 2000s, Dragoie said. But today’s multilaterals are longer, more complex and more productive.

The main play is in Alberta’s Marten Hills region, where producers are using multilaterals to produce shallow heavy oil. 

Today’s average multilateral has about 7.5 horizontal legs from a single surface location, up from four or six just a few years ago, Dragoie said. 

One record-setting well in Alberta drilled by Tamarack Valley Energy in 2023 features 11 legs stretching two miles each, for a total subsurface reach of 33 kilometres — the longest well in Canada.

By accessing large volumes of oil and gas from a single surface pad, multilaterals reduce land impact by a factor of five to ten compared to conventional wells, he said.

The designs save money by skipping casing strings and cement in each leg, and production is amplified as a result of increased reservoir contact.

Here are examples of multilateral well design. Images courtesy Chinook Consulting Services.

Parallel

Fishbone

Fan

Waffle

Stingray

Frankenwells

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In Alberta’s oil patch, some companies are going beyond their obligations to clean up inactive wells. 

Aspenleaf Energy operates in the historic Leduc oil field, where drilling and production peaked in the 1950s. 

In the last seven years, the privately-held company has spent more than $40 million on abandonment and reclamation, which it reports is significantly more than the minimum required by the Alberta Energy Regulator (AER). 

CEO Bryan Gould sees reclaiming the legacy assets as like paying down a debt. 

“To me, it’s not a giant bill for us to pay to accelerate the closure and it builds our reputation with the community, which then paves the way for investment and community support for the things we need to do,” he said. 

“It just makes business sense to us.”

Aspenleaf, which says it has decommissioned two-thirds of its inactive wells in the Leduc area, isn’t alone in going beyond the requirements.

Producers in Alberta exceeded the AER’s minimum closure spend in both years of available data since the program was introduced in 2022.

That year, the industry-wide closure spend requirement was set at $422 million, but producers spent more than $696 million, according to the AER.

In 2023, companies spent nearly $770 million against a requirement of $700 million.

Alberta’s number of inactive wells is trending downward. The AER’s most recent report shows about 76,000 inactive wells in the province, down from roughly 92,000 in 2021.

In the Leduc field, new development techniques will make future cleanup easier and less costly, Gould said.

That’s because horizontal drilling allows several wells, each up to seven kilometres long, to originate from the same surface site.

“Historically, Leduc would have been developed with many, many sites with single vertical wells,” Gould said.  

“This is why the remediation going back is so cumbersome. If you looked at it today, all that would have been centralized in one pad. 

“Going forward, the environmental footprint is dramatically reduced compared to what it was.”

During and immediately after a well abandonment for Aspenleaf Energy near Edmonton. Photos for the Canadian Energy Centre

Gould said horizontal drilling and hydraulic fracturing give the field better economics, extending the life of a mature asset.  

“We can drill more wells, we can recover more oil and we can pay higher royalties and higher taxes to the province,” he said. 

Aspenleaf has also drilled about 3,700 test holes to assess how much soil needs cleanup. The company plans a pilot project to demonstrate a method that would reduce the amount of digging and landfilling of old underground materials while ensuring the land is productive and viable for use.

Crew at work on a well abandonment for Aspenleaf Energy near Edmonton. Photo for the Canadian Energy Centre

“We did a lot of sampling, and for the most part what we can show is what was buried in the ground by previous operators historically has not moved anywhere over 70 years and has had no impact to waterways and topography with lush forestry and productive agriculture thriving directly above and adjacent to those sampled areas,” he said. 

At current rates of about 15,000 barrels per day, Aspenleaf sees a long runway of future production for the next decade or longer.  

Revitalizing the historic field while cleaning up legacy assets is key to the company’s strategy. 

“We believe we can extract more of the resource, which belongs to the people of Alberta,” Gould said. 

“We make money for our investors, and the people of the province are much further ahead.”

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Alberta’s oil sands sector is one of Canada’s most important industries — and also one of its most misunderstood.

Here are five common myths, and the facts behind them.

Myth: Oil sands emissions are unchecked

Steam generators at a SAGD oil sands production site in northern Alberta. Photo courtesy Cenovus Energy

Reality: Oil sands emissions are strictly regulated and monitored. Producers are making improvements through innovation and efficiency.

The sector’s average emissions per barrel – already on par with the average oil consumed in the United States, according to S&P Global – continue to go down. 

The province reports that oil sands emissions per barrel declined by 26 per cent per barrel from 2012 to 2023. At the same time, production increased by 96 per cent.

Analysts with S&P Global call this a “structural change” for the industry where production growth is beginning to rise faster than emissions growth.

The firm continues to anticipate a decrease in total oil sands emissions within the next few years. 

The Pathways Alliance — companies representing about 95 per cent of oil sands activity — aims to significantly cut emissions from production through a major carbon capture and storage (CCS) project and other innovations.

Myth: There is no demand for oil sands production

Expanded export capacity at the Trans Mountain Westridge Terminal. Photo courtesy Trans Mountain Corporation

Reality: Demand for Canadian oil – which primarily comes from the oil sands – is strong and rising. 

Today, America imports more than 80 per cent more oil from Canada than it did in 2010, according to the U.S. Energy Information Administration (EIA).

New global customers also now have access to Canadian oil thanks to the opening of the Trans Mountain pipeline expansion in 2024. 

Exports to countries outside the U.S. increased by 180 per cent since the project went into service, reaching a record 525,000 barrels per day in July 2025, according to the Canada Energy Regulator. 

The world’s appetite for oil keeps growing — and it’s not stopping anytime soon.

According to the latest EIA projections, the world will consume about 120 million barrels per day of oil and petroleum liquids in 2050, up from about 104 million barrels per day today.

Myth: Oil sands projects cost too much

Heavy haulers at an oil sands mining operation in northern Alberta. Photo courtesy Suncor Energy

Reality: Operating oil sands projects deliver some of the lowest-cost oil in North America, according to Enverus Intelligence Research.  

Unlike U.S. shale plays, oil sands production is a long-life, low-decline “manufacturing” process without the treadmill of ongoing investment in new drilling, according to BMO Capital Markets.  

Vast oil sands reserves support mining projects with no drilling, and the standard SAGD drilling method involves about 60 per cent fewer wells than the average shale play, BMO says. 

After initial investment, Enverus says oil sands projects typically break even at less than US$50 per barrel WTI. 

Myth: Indigenous communities don’t support the oil sands 

Chief Greg Desjarlais of Frog Lake First Nation signs an agreement in September 2022 whereby 23 First Nations and Métis communities in Alberta acquired an 11.57 per cent ownership interest in seven Enbridge-operated oil sands pipelines for approximately $1 billion. Photo courtesy Enbridge

Reality: Indigenous communities play an important role in the oil sands sector through community agreements, business contracts and, increasingly, project equity ownership.  

Oil sands producers spent an average of $1.8 billion per year with 180 Indigenous-affiliated vendors between 2021 and 2023, according to the Canadian Association of Petroleum Producers. 

Indigenous communities are now owners of key projects that support the oil sands, including Suncor Energy’s East Tank Farm (49 per cent owned by two communities); the Northern Courier pipeline system (14 per cent owned by eight communities); and the Athabasca Trunkline, seven operating Enbridge oil sands pipelines (~12 per cent owned by 23 communities). 

These partnerships strengthen Indigenous communities with long-term revenue, helping build economic reconciliation.

Myth: Oil sands development only benefits people in Alberta 

The Toronto Stock Exchange (TSX) on Bay St. Getty Images photo

Reality: Oil sands development benefits Canadians across the country through reliable energy supply, jobs, taxes and government revenues that help pay for services like roads, schools and hospitals.  

The sector has contributed approximately $1 trillion to the Canadian economy over the past 25 years, according to analysis by the Macdonald-Laurier Institute (MLI). 

That reflects total direct spending — including capital investment, operating costs, taxes and royalties — not profits or dividends for shareholders.

More than 2,300 companies outside of Alberta have had direct business with the oilsands, including over 1,300 in Ontario and almost 600 in Quebec, MLI said. 

Energy products are by far Canada’s largest export, representing $196 billion, or about one-quarter of Canada’s total trade in 2024, according to Statistics Canada. 

Led by the oil sands, Canada’s energy sector directly or indirectly employs more than 445,000 people across the country, according to Natural Resources Canada. 

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