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Growth, Discipline and Innovation Will Define the Next Chapter
By EnergyNow Editorial Staff
For most of their modern history, Alberta’s oil sands have been associated with one word, growth. Massive mines, multi-billion-dollar upgraders and enormous steam-assisted gravity drainage projects transformed northern Alberta into one of the world’s great energy-producing regions.
But the next chapter of the oil sands is likely to look very different.
Growth is still very much on the table. Alberta Premier Danielle Smith wants significantly more production, the federal government has become more receptive to additional energy infrastructure, and a proposed new West Coast pipeline could eventually create room for another one million barrels per day of Canadian crude exports. But oil sands operators are making it increasingly clear that growth must be accompanied by something else, capital discipline, operational reliability, lower costs and continued technological innovation.
That balance may define the oil sands for the next 20 years.
From 2.5 Million to More Than 3.5 Million Barrels a Day
The transformation that has already taken place is significant.
Oil sands bitumen production averaged approximately 2.53 million barrels per day in 2015. By 2024, Alberta Energy Regulator data showed combined mined and in-situ bitumen production averaging approximately 3.56 million barrels per day—an increase of roughly 41 per cent in less than a decade. The AER forecasts raw bitumen production could reach about 4.06 million barrels per day by 2034 under its base case.
The growth has continued. Canada set another crude production record in 2025, averaging 5.35 million barrels per day nationally. Alberta alone added approximately 182,000 barrels per day compared with 2024, with the Canada Energy Regulator saying the increase was driven primarily by rising non-upgraded bitumen production.
What is especially important is how much of that growth has occurred.
The industry has not built another wave of giant greenfield projects comparable with those developed during the oil sands construction boom of the 2000s and early 2010s. Instead, operators have extracted more production from existing facilities through debottlenecking, improved maintenance practices, better reservoir management, additional well pads, automation and improved reliability.
That is likely a preview of what comes next.
The New Growth Model: More Barrels From Existing Assets
Oil sands facilities have an enormous advantage over many other petroleum resources: once built, they are extraordinarily long-lived and have relatively low natural decline rates. That means operators can sustain, and increasingly expand, production without replacing enormous percentages of their output every year.
This creates opportunities to add tens of thousands of barrels at a time through relatively modest investments rather than immediately committing billions of dollars to new standalone developments.
Suncor is perhaps the clearest example. At its March 2026 Investor Day, the company outlined plans for approximately 100,000 barrels per day of additional upstream production by 2028 while simultaneously targeting a US$5-per-barrel reduction in its corporate WTI breakeven price.
Suncor is also planning a major long-term shift toward in-situ development. CEO Rich Kruger told investors in March that the economics increasingly favour those barrels.
“All barrels are not created equal.”
Kruger said Suncor’s in-situ production currently generates roughly twice the relative cash flow per barrel of its mining operations. The company expects approximately 60 per cent of its oil sands bitumen production to come from in-situ operations by 2040, compared with about 30 per cent today.
Firebag illustrates the opportunity. The operation produces around 245,000 barrels per day, with Suncor targeting approximately 275,000 barrels per day by 2028 through optimization and debottlenecking. Longer term, the company has applied to increase Firebag’s permitted capacity substantially and has additional in-situ resources available through projects such as Lewis.
This is not simply production growth. It is capital-efficient growth.
Syncrude: Reliability Is Growth
The same philosophy increasingly applies to the large mining operations.
At Syncrude, the next phase is as much about extending asset life, reliability and operational excellence as it is about simply producing more barrels.
Andrew Rosser, Senior Vice President, Syncrude Operations, captured the longer-term perspective while discussing the Mildred Lake Extension in 2025:
“We’re not just mining; we are building a legacy for our community and our country.”
The comment was reported by International Mining following first oil sands ore from the Mildred Lake Extension West project, which is designed to help sustain Syncrude production as its existing North Mine approaches the end of its operating life.
That is an increasingly important distinction.
For assets such as Syncrude, Suncor Base Plant, Fort Hills, Horizon and Kearl, maintaining production capacity can itself represent a major accomplishment. Mines need new pits, replacement equipment and continuing investment in extraction systems, tailings management and upgrading facilities.
Reliability therefore becomes one of the cheapest forms of growth. Every additional percentage point of utilization can translate into millions of additional barrels without constructing another major facility.
Innovation Has Already Changed the Emissions Equation
The other major part of the oil sands story is technology.
Production has risen dramatically, but emissions per barrel have moved in the opposite direction. Alberta government data show that the emissions intensity of oil sands bitumen production declined by approximately 28 per cent per barrel between 2012 and 2024, even as bitumen production increased by 105 per cent over that period.
Those improvements have come from dozens of innovations rather than a single breakthrough.
In-situ operators have improved steam-oil ratios, meaning less natural gas and water are required to produce each barrel. Cogeneration facilities produce electricity and steam more efficiently. Better reservoir modelling allows operators to place wells more precisely. Solvent technologies are being developed to reduce steam requirements further.
Mining operations are also changing. Imperial’s Kearl operation has converted its haul-truck fleet to autonomous operation, while its proprietary froth-treatment process eliminates the need for an on-site upgrader, reducing energy requirements. Kearl produced about 280,000 barrels per day in 2025.
Digital technology, sensors, artificial intelligence and predictive maintenance are increasingly helping operators identify equipment problems before failures occur—improving safety while reducing downtime and cost.
The next major emissions opportunity is carbon capture and storage.
In July 2026, Alberta, Ottawa and Canada’s five largest oil sands producers signed a memorandum establishing a framework intended to advance both additional production and the Pathways carbon capture project. The proposed system is initially expected to transport and permanently store about six million tonnes of CO₂ annually and ultimately contribute toward approximately 16 million tonnes of annual emissions reductions.
But the agreement is also an example of one of the industry’s biggest challenges: Certainty.
Operators Are Ready to Grow – But Not at Any Price
Governments may want more production, but shareholders still control the capital.
Canadian Natural CEO Scott Stauth made that point particularly clearly in August when the company said it would not advance several medium- and longer-term oil sands expansions until the framework negotiated with Alberta and Ottawa is converted into definitive agreements.
“It’s extremely important that we get this right.”
Among the projects remaining on hold are Canadian Natural’s roughly 30,000-barrel-per-day Jackfish expansion, the approximately 70,000-barrel-per-day Pike 2 development and the potential 150,000-barrel-per-day Jackpine mine expansion.
Suncor has expressed similar caution. Despite the significantly more supportive government environment, Rich Kruger said in August that Suncor was not yet prepared to accelerate beyond the growth plans laid out at its March Investor Day.
Cenovus CEO Jon McKenzie, meanwhile, described the government-industry agreement surrounding Pathways and future oil sands development as “meaningful progress”, even as companies wait to see how the final fiscal, carbon-pricing and regulatory arrangements work in practice.
That tells us something important about the future.
The oil sands industry of the 2020s is unlikely to chase production growth simply because oil prices are high or politicians want more barrels. Investors expect debt control, dividends, share repurchases and competitive returns on capital.
New production will have to compete for investment.
Pipeline Capacity Remains the Gatekeeper
And then there is the recurring Alberta problem, where will the additional barrels go?
The Trans Mountain Expansion changed the equation dramatically when it entered service in May 2024. The expanded system now has approximately 890,000 barrels per day of capacity, increasing western Canadian export pipeline capacity by about 13 per cent and vastly increasing direct tidewater access. Canadian crude exports to destinations outside the United States subsequently more than tripled.
The expansion also helped narrow the WTI-WCS differential, improving the value received for Canadian barrels.
But that new capacity is already being absorbed.
The CER reported combined western Canadian pipeline capacity of approximately 5.2 million barrels per day in June 2025, with the overall export system remaining highly utilized.
That is why the proposed new West Coast pipeline matters so much.
Alberta submitted a proposal in July for a pipeline capable of moving more than one million barrels per day from the Edmonton-area hub at Bruderheim to British Columbia’s southwest coast. The province argues the project would provide the export capacity required to support another major increase in Alberta production.
Alberta’s Premier Danielle Smith has made her ambition clear.
“Canada has everything it needs to become an energy superpower, but only if we build the infrastructure to get our resources to market.”
Her government has gone even further, establishing a goal of eventually doubling Alberta oil production to approximately eight million barrels per day over the next 10 to 15 years.
Whether eight million barrels per day is realistic remains open to debate. Reaching anything close to that level would require enormous investments in production, pipelines and supporting infrastructure.
It would also require regulatory certainty, Indigenous consultation and participation, competitive carbon policy, continuing reductions in emissions intensity and confidence that global markets will need—and pay competitively for—the additional barrels.
The Challenges Ahead
The resource itself is not the problem. Alberta has enough oil sands resource to produce for generations.
The challenge is making the next barrel competitive.
Operators will have to manage aging infrastructure and increasingly complex maintenance programs. Labour and construction costs will matter. Water use, tailings management and reclamation will remain important environmental and community issues. Wildfires and extreme weather have already demonstrated their potential to disrupt production.
Above all, global oil prices remain beyond Alberta’s control. A project that looks attractive at US$80 oil may look very different at US$50.
That is precisely why capital discipline has become so important.
Where Do the Oil Sands Go From Here?
Probably higher, but differently.
The next million barrels per day of oil sands production is unlikely to arrive through a repeat of the enormous construction boom that created the industry’s existing footprint.
Instead, growth will increasingly come incrementally: another 20,000 barrels here, 40,000 there, a debottlenecked facility, improved steam efficiency, another well pad, longer maintenance intervals, better mine productivity and higher operating reliability.
At the same time, projects such as Pathways, solvents, automation, digital operations and improved extraction technologies will determine whether Canadian heavy oil can continue lowering its cost and carbon intensity.
And pipelines will ultimately determine how far that growth can go.
The central challenge for Andrew Rosser and every other senior oil sands operator is no longer simply how to produce more oil.
It is how to produce more oil safely, reliably, efficiently and competitively while using less energy, lowering emissions per barrel and generating acceptable returns for investors.
That is the new oil sands equation.
Alberta possesses the resource. Technology continues to improve. Governments increasingly appear interested in facilitating growth. Global energy security has given Canada another opportunity to strengthen its position as a major supplier.
But operators will decide where the capital goes.
And for the Alberta’s oil sands, the companies that master the balance between growth, discipline and innovation will determine where the industry goes from here.
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