AECO vs. Henry Hub: is Canadian gas about to become the world’s cheapest LNG feedstock?

Canada’s AECO natural gas benchmark has emerged as a critical factor in the global LNG cost equation, positioning Western Canadian feedstock as one of the cheapest sources for export. As of mid-2025, AECO is trading near C$1.45 per gigajoule (GJ), or roughly US$1.29 per million British thermal units (MMBtu), while the U.S. Henry Hub benchmark hovers around US$2.41 per MMBtu. This widening differential is reshaping project economics for new LNG terminals, particularly Shell-led LNG Canada and Indigenous-majority-owned Cedar LNG in British Columbia.

With Asia-bound cargoes already departing from Kitimat and new terminals nearing financial close, institutional analysts are increasingly focused on whether Canada’s gas pricing dynamics could give it a long-term cost advantage over traditional U.S. Gulf Coast exporters. If the current AECO-Henry Hub spread holds, Canadian LNG could become structurally cheaper on a delivered basis, especially when factoring in shipping distances and carbon intensity.

What historical trends have driven the price gap between AECO and Henry Hub gas markets over the past decade?

The AECO price discount is not a recent anomaly but the result of a decade-long pattern driven by regional oversupply and limited pipeline egress. Western Canadian production from formations like the Montney has outpaced infrastructure capacity, often flooding the Alberta market and depressing prices. Between 2015 and 2021, AECO typically traded at a 30–40 percent discount to Henry Hub. At times of storage saturation, the spread widened further, with AECO even turning negative during seasonal shoulder months.

According to Alberta’s Energy Regulator, AECO fell as low as C$0.05/GJ (under US$0.04/MMBtu) in September 2024 as regional storage filled and producers faced constraints on egress pipelines. Meanwhile, Henry Hub retained more stability due to its proximity to high-demand centers and established LNG hubs in the Gulf of Mexico. The result has been a structural basis differential that investors are now viewing as a potential arbitrage opportunity for Canadian LNG exporters.

How does a lower AECO price impact the competitiveness of Canadian LNG projects like LNG Canada and Cedar LNG?

For LNG exporters, feed gas cost is the single largest operating expense. With AECO consistently below US$2/MMBtu and often under US$1/MMBtu, LNG Canada and Cedar LNG benefit from significantly lower input costs compared to U.S. Gulf Coast facilities sourcing from Henry Hub. At current differentials, Canadian LNG projects may enjoy a margin uplift of up to US$1.50–2.00 per MMBtu, according to institutional analysts monitoring the LNG value chain.

Shell executives have explicitly pointed to AECO indexation as a core advantage for LNG Canada, noting that it positions the terminal competitively against global peers. With the first cargo now shipped and full-scale exports expected later in 2025, investors are beginning to see AECO as more than just a regional marker—it is becoming an embedded cost advantage in the global LNG ecosystem.

Cedar LNG, which also taps into the Coastal GasLink network connected to AECO gas fields, is projected to enjoy similar cost benefits. Combined with its electrified floating LNG (FLNG) design powered by BC Hydro, Cedar LNG offers a compelling case for low-carbon, low-cost LNG supply targeting Northeast Asia.

What supply, storage, and infrastructure constraints continue to affect AECO basis pricing trends?

Despite its pricing advantage, AECO’s persistently low value is also a symptom of unresolved constraints. The Western Canadian Sedimentary Basin (WCSB) continues to produce more gas than local markets can absorb, especially during off-peak heating seasons. Alberta’s underground storage, one of North America’s largest, routinely reaches maximum capacity ahead of winter.

Pipeline takeaway capacity remains a bottleneck. While projects like Coastal GasLink are beginning to alleviate this, other major export corridors remain congested. Seasonal maintenance on TC Energy’s Alberta and Nova Gas Transmission systems further exacerbates volatility.

Until new LNG export facilities consistently draw down WCSB surplus, AECO is likely to remain structurally discounted. That said, industry expectations suggest that by 2026–2027, Canadian LNG exports could absorb more than 2 Bcf/day of excess supply, potentially stabilizing AECO above C$2.50/GJ but still below Henry Hub.

Are U.S. Gulf Coast LNG projects still the benchmark, or is Canadian LNG gaining price and ESG ground?

While U.S. LNG projects remain dominant in scale and volume, Canada is gaining ground on cost competitiveness. Feedstock prices are a key differentiator, but shipping routes are another. Canadian terminals in Kitimat are 10–12 days closer to Northeast Asian ports compared to those on the Gulf Coast. This cuts voyage costs and allows for more flexible cargo scheduling.

Moreover, ESG factors are increasingly shaping offtake agreements. Both LNG Canada and Cedar LNG are powered by hydroelectricity from BC Hydro, resulting in some of the lowest carbon intensity scores globally. Cedar LNG has emphasized its emissions profile—approximately 0.08 tonnes CO₂e per tonne of LNG—as a key commercial differentiator.

Institutional investors, especially those with ESG mandates, are beginning to factor emissions into pricing forecasts. Canadian LNG may command a green premium in the coming years, especially if buyers are required to account for Scope 3 emissions.

Can Western Canadian gas remain structurally cheaper as demand grows from expanding LNG and power generation use?

Forecasts from Alberta’s Energy Regulator suggest AECO prices will rise to C$2.71/GJ (US$2.20/MMBtu) in 2025 and C$3.82/GJ (US$3.10/MMBtu) by 2026. These projections assume LNG Canada ramps to full capacity and additional industrial demand—including hydrogen and petrochemicals—begins to materialize.

However, even at C$3.82/GJ, AECO remains competitive against Henry Hub, especially when factoring in shipping advantages and lower liquefaction emissions. Moreover, with long-term global LNG prices expected to average US$8–10/MMBtu through 2030, Canadian exporters could retain a healthy margin.

To maintain this edge, producers and developers will need to continue investing in midstream flexibility, storage expansion, and emissions performance. Failure to expand egress pipelines or balance production growth could reintroduce volatility and dampen AECO’s long-term arbitrage value.

What should investors and stakeholders monitor in the evolving AECO-to-LNG cost arbitrage scenario?

Stakeholders should watch several key variables over the next 12–24 months. First, the performance and ramp-up of LNG Canada will set the benchmark for how efficiently AECO-linked supply can be monetized. Second, the financial close and execution progress at Cedar LNG will signal whether Canada’s Indigenous-majority infrastructure model can scale.

Institutional investors will also monitor developments around carbon pricing, ESG certification for LNG cargos, and geopolitical LNG demand shifts—particularly from China, South Korea, and Japan. Any uptick in domestic gas demand from hydrogen hubs or industrial switchovers could tighten AECO supply and alter the current spread.

Lastly, infrastructure developments—especially new gas storage capacity and interconnectivity between Alberta and B.C.—will shape whether AECO remains a long-term discount market or converges toward parity with Henry Hub.