Transporting Canadian heavy oil typically requires a 70:30 blend ratio of oil to condensate. Canada produces about 570,000 bpd of condensate, mainly from unconventional plays in the Montney and Duvernay. The remainder of the condensate used in the diluent pool is imported from the US through Pembina’s Cochin pipeline (95,000 bpd) and Enbridge’s Southern Lights pipeline (195,000 bpd). Earlier this year, Enbridge commissioned 15,000 bpd of additional capacity in Southern Lights to accommodate near-term heavy oil expansions. With both pipeline systems running at or near capacity, Alberta’s diluent pool strongly relies on growth in domestic condensate production to fill any shortfalls. Absent domestic supply growth railed imports from the US may be required to meet the growing diluent demand, which would raise diluent costs for Alberta’s heavy oil producers.  

With crude oil egress in Western Canada expected to tighten around 2027, midstream operators have announced brownfield expansion plans to boost incremental capacity by about 840,000 bpd. Trans Mountain expects to add about 360,000 bpd to its west coast pipeline and Enbridge expects to increase its US export capacity through a series of phases totaling 430,000 bpd. In total this will add about 790,000 bpd of added egress between 2027 to the early 2030s with the potential for this number to be even higher with Enbridge flagging potential further optimization phases (3 and 4) of its Mainline system at a later date.

Gibson Energy announced at its Investor Day presentation its plans to deploy up to C$1 billion ($710 million) of growth capital over the next five years. The initiatives include plans to expand its patented Diluent Recovery Unit (DRU) by 50,000 bpd starting in 2028 – with an additional 50,000 bpd of capacity available if needed. The significance of this expansion is that it not only increases Western Canadian crude oil egress by rail, but it also returns diluent (condensate) to the Alberta diluent pool. Given that condensate is priced approximately on par with the West Texas Intermediate (WTI) oil price, it is at a premium to the price of fully blended heavy oil. This alternative transport method could spur interest from shippers looking to boost volumes while reducing cost exposure to condensate.  

With a wave of additional oil takeaway capacity expected to hit the market, the prospect of a greenfield AB-BC pipeline could push combined egress capacity additions to roughly 2 million bpd. There are, however, several hurdles to be overcome before an official proposal is submitted to the Major Projects office by 1 July 2026. These include: a private sector proponent, provincial and indigenous cooperation, an amendment to the oil tanker ban, and the synchronized development of Pathways Alliance’s Phase 1 carbon capture project. While the MoU provides a framework for a potential new pipeline, the number of requirements and uncertainties makes underwriting a project of this scale, still rather speculative despite the new agreement.

Rystad Energy’s base case scenario sees 840,000 bpd day of additional egress built in Western Canada within the next decade. This would require roughly 214,200 bpd of additional condensate for transport, assuming an 85% throughput utilization rate. Based on domestic condensate supply growth forecasts of roughly 150,000 bpd within the next decade, the basin is left with a minor shortfall of 64,200 bpd of required condensate, highlighted in Figure 1. With incremental capacity available on Southern Lights (15,000 bpd) and expansion of DRUs (50,000 to 100,000 bpd), the shortfall is likely to be met by these sources, leaving the condensate market tightly balanced.

In a high case scenario where the proposed AB-BC pipeline gets built along with further expansions on Enbridge’s Mainline system (phases 3 and 4), the implied condensate shortfall jumps even higher to about 383,000 bpd – also assuming 85% throughput utilization. Based on the significant condensate requirements and lack of available import capacity, it is unlikely domestic condensate supply could scale to this level without additional natural gas egress. As a costly alternative, oil sands players could look to supply condensate through rail imports or even Synthetic Crude Oil (SCO) as diluent. However, depending on future oil prices, these higher cost options could have implications for netbacks.

On the surface, the latest MoU is a marked improvement and welcomed change towards cooperation around resource and infrastructure development. With the narrative on long- term Canadian oil production gaining momentum around the latest prospects of egress expansions, condensate continues to be a key pillar of future oil sands growth. Against a backdrop of growing liquefied natural gas (LNG) demand and rising call on domestic condensate, unconventional operators will continue to accelerate the development and scale of high value liquids-rich plays in Montney and Duvernay. At the same time, local natural gas markets will face downward pressure as gas growth associated with domestic condensate production could risk over supplying Canadian gas markets. While there are still uncertainties around the recent MoU and exactly how the broad energy and climate-policy agreement will play out, the overall progression towards greater cooperation is a positive sign and one that can create new tailwinds for Canada’s oil and gas sector heading into the future.

Taylor Lee
Vice President, Oil & Gas Research
taylor.lee@rystadenergy.com