1 basin, 2 narratives: Why B.C.’s LNG and Alberta’s heavy oil are more intertwined than they appear

Canada’s pipeline debate increasingly sounds like a choice between betting on LNG or heavy crude—a binary between British Columbia and Alberta. Right now, the political momentum is clearly behind liquefied natural gas. B.C. is all in on LNG, and its goals are featured prominently in Prime Minister Mark Carney’s immediate “build, baby, build” agenda. Part of the justification rests on a careful rebrand. LNG is billed as a “transition fuel”—a middle path that reduces coal dependence overseas while preserving industrial growth at home. LNG Canada, for example, is positioned as a wealth-generating, climate-aligned export strategy. Oilsands production, by contrast, is often treated as yesterday’s story—politically fraught, emissions-heavy, tolerated for the royalties and employment it sustains, but unworthy of another pipeline to tidewater. The implicit narrative is one of divergence. Canada can lean into gas while slowly managing down bitumen, or so it seems for those who are more willing to accept the former. But that framing misses something fundamental about how the Western Canadian resource system actually works. Simply put, the drilling that feeds LNG terminals also supplies the diluent that moves bitumen. And oilsands production, in turn, creates steady demand for the liquids that make gas drilling economic. This means Canada’s LNG and oilsands are not separate bets. Importantly, the two commodities can buffer one another against market volatility. Industry veteran Richard Masson, former CEO of the Alberta Petroleum Marketing Commission, points to the cancelled Northern Gateway project as a reminder that this integration was once openly acknowledged. “Northern Gateway was two pipelines,” he said. Diluted bitumen would move west from northern Alberta, with condensate going east in the same trench. “You end up with this super synergy between the different segments of the business,” Masson said. “It is a big thing. People don’t talk about it at all.” They should. Because this isn’t simply about global markets. It’s about exposure within a North American network still shaped—and often constrained—by the thousand-pound bully that is the United States. Understanding our energy integration would bolster Canada’s economic sovereignty—and could begin to bridge the political divide between B.C. and Alberta, whose economies are already bound together beneath the surface. Gas fields straddling B.C. and Alberta The Montney Formation stretches across northeastern B.C. and into northwestern Alberta. It sits west and slightly south of the oilsands region, but well within the same Western Canadian sedimentary basin. The Duvernay lies further south in central Alberta. Together, these formations have become Canada’s dominant source of new natural gas supply. But they produce more than just gas. They yield methane—used for heating homes and generating electricity—alongside heavier hydrocarbons such as ethane, propane, butane, and pentane. Pentane is the other key molecule in this equation. Bitumen is too viscous to move through a pipeline on its own. It must be blended with roughly 25- to 30-percent condensate to meet pipeline specifications. Without that diluent, oilsands production would effectively be landlocked. Western Canada is structurally short on condensate. For years, producers have imported hundreds of thousands of barrels per day from the U.S., much of it moving north from Texas through Chicago before reaching Alberta. That dependence is rarely part of the public conversation. Susan Bell, who leads crude oil market analysis for the Americas at Rystad Energy, says that reality helps explain why drilling continues in liquids-rich basins even when gas prices are soft. “Because they’re making so much money on the liquids, and they’re making money on the liquids because the liquids have a demand right at their back door for bitumen blending,” she told The Hub. Masson puts it more bluntly. “People drill for pentane—for the diluent—and then have to deal with the other things,” he said. The “other things” are methane—the very gas LNG facilities are built to export—along with propane and butane that must also find markets. “In fact, the abundance of methane means prices in Alberta and B.C. are typically the lowest in North America,” Masson said. “For most oilsands projects, this is an additional benefit, as methane is the largest operating cost providing the steam to liberate the bitumen from the ground.” A volatile LNG cycle This interdependence matters, particularly as LNG markets enter a volatile phase. Rystad’s LNG expert Mathieu Utting expects unprecedented supply growth in the coming years. “There’s an extraordinary amount of LNG capacity coming online,” he said. “Basically set to double by 2029, an increase that really hasn’t been seen in the history of LNG development.” That surge is expected to suppress prices, with the trough likely around 2030 or 2031. Projects like LNG Canada Phase 2 may not be cancelled, but they could be delayed into the mid-2030s, when prices are expected to recover. Oilsands production will not rescue Canadian LNG from a global glut. But it can help sustain the liquids-rich drilling that might otherwise slow sharply in a prolonged weak gas price environment. If B.C. is counting on natural gas royalties to support its provincial budget, it should also recognize that those revenues are partially underwritten by demand from Alberta’s oilsands. A shared export horizon But the two energy sources also share the same destiny. Both LNG and oilsands exports are increasingly pointing west. For decades, Canada’s crude oil strategy was oriented south. Heavy barrels flowed to the U.S. Midwest and then the Gulf Coast, where complex refineries process them. That relationship still matters, but it is no longer uncontested. Venezuelan heavy crude is re-entering global markets. Incremental increases in volumes could displace some Canadian barrels in the Gulf, pushing Western Canadian crude to seek other outlets. The answer is increasingly Asia. The success of the Trans Mountain Pipeline expansion underscores that shift. China, in particular, has built—and continues to build—sophisticated refining capacity designed to process heavy crude and convert it into petrochemicals and jet fuel. Western Canadian heavy is technically well-suited to that configuration. LNG, of course, was always geared toward Asia. “I think we sometimes talk about Canada pushing our supply onto the global market, but really it’s a demand pull,” said Mark Parsons, chief economist with ATB Financial. “That’s why you’ve come to Canada asking for our gas—for our LNG,” he continued. “The Chinese also have refineries equipped to process heavy grades of crude, so that they are keen to purchase our oil.” For China, the continued consumption of hydrocarbons in both forms reflects an integrated, national industrial strategy. Natural gas displaces coal in power generation, lowering emissions intensity while enabling the country to ramp up manufacturing capacity. Heavy crude feeds complex refineries optimized for petrochemicals—the building blocks of all the stuff China is trying to make with its factories. It’s really that simple. So it is strikingly counterintuitive that Canada continues to debate these two resources as though they exist in opposition or separate realms. Cleaner power doesn’t automatically eliminate industrial hydrocarbon demand. In some cases, it intensifies it. Heavy crude is not simply about gasoline and diesel—however fixated Canadian debates may be on transportation fuels. It is also a feedstock for plastics, industrial resins, solvents, and asphalt. Ironically, even EVs depend on it for the roads and the parts. If heavy crude is constrained, substitutes emerge. China retains vast coal reserves and is already investing in coal-to-chemicals technologies that convert coal into petrochemical feedstocks. Proponents of LNG already understand this substitution logic. It’s the very premise behind calling natural gas a transitional fuel. If gas is unavailable—the argument goes—coal will fill the gap. And coal, as we all know, is much more emissions-intensive. This structural reality applies to oil as well. Political disconnect Right now, B.C.’s LNG narrative emphasizes transition and climate pragmatism, while Alberta’s oilsands push tends to lean on economic growth and global energy demand. Ottawa, meanwhile, oscillates between industrial ambition and emissions targets. What’s missing is a coherent articulation of how these pieces fit together. We could begin by acknowledging something much more basic—something the geology already makes clear underneath the provincial boundaries of B.C. and Alberta. The Montney and the oilsands sit within the same sedimentary basin, formed over hundreds of millions of years. The rocks do not recognize interprovincial barriers or ideological differences. Above ground, however, the two provinces often speak as though they represent competing energy futures. It doesn’t have to be so. For the sake of Canadian unity—and sovereignty—we would be wise to recognize what the markets already know.