Discounted pricing at the NOVA/AECO C natural gas hub in Southern Alberta is likely to remain a fact of life over the near term, even if pipeline expansions and LNG exports in Western Canada come online as scheduled, according to experts.
Abundant gas supply from the Western Canadian Sedimentary Basin (WCSB) and limited egress capacity out of the region have historically kept downward pressure on the price of gas delivered to AECO, the hub that is synonymous with TC Energy Corp.’s Nova Gas Transmission Ltd. (NGTL) pipeline system.
Pipeline maintenance on NGTL can also cause AECO prices to collapse as molecules have nowhere to go.
As a result, producers and marketers of Western Canadian gas have sought to maximize their exposure to higher prices in the United States and/or Eastern Canada. The challenge, however, is a lack of available firm transport capacity out of the AECO region and into these more lucrative markets.
There simply is “no more pipe out of the basin,” a Calgary-based natural gas trader who did not want to be named told NGI. “It’s all contracted…so there’s not a lot of egress for the next little while.”
Additionally, associated gas from the Bakken Shale of North Dakota has been displacing Canadian volumes on TC’s Northern Border pipeline system, which connects WCSB supply with demand in the U.S. Midwest, according to FactSet Research Systems Inc’s Connor McLean, senior energy analyst.
With pipeline space already limited, “any of that capacity that gets displaced really just backs up into the AECO market,” McLean told NGI.
Limited capacity beyond Alberta’s borders also can hinder the ability of Canadian gas to respond to price signals in the Western United States, he said.
“The marginal molecule for the western U.S. is not Canada,” McLean said, but rather the Opal Hub in southwestern Wyoming. He explained that “Canadian gas is flowing as much as it can across the border, and every incremental molecule that California or Nevada or Utah needs, has to come from the Western Rockies.”
NGI’s Opal forward basis curve showed a $6.25 premium to U.S. benchmark Henry Hub for the balance of winter (February-March) as of Wednesday’s (Jan. 4) trading day, according to NGI’s Forward Look.
NOVA/AECO C gas for the balance of winter, meanwhile, was trading at an 83.9-cent/MMBtu discount. For summer 2024 (April-October), when maintenance on NGTL is expected to impact flows out of the region, the basis discount stood at $1.405. For the 2024/2025 winter (November-March), NOVA/AECO C gas was trading at $1.282 below Henry Hub.
What About LNG?
Liquefied natural gas exports from British Columbia (BC) could potentially offer some upside to AECO pricing. There are several LNG projects in the works in Canada, with one set to begin service in BC within two years.
TC’s Coastal Gaslink pipeline is slated to add 2.1 Bcf/d of takeaway capacity to the Shell plc-led LNG Canada terminal under construction in Kitimat, BC. The pipeline is expected to be mechanically complete by the end of this year. LNG Canada’s in-service date is forecast for 2025.
“In theory, all else being equal, that tightens the supply/demand balance,” the Calgary trader said. “However, a certain amount of that has got to be priced into the market already…And then I think there’s such vast amounts of gas in this part of the world that a lot of the export molecules will be met with a fresh production molecule.”
McLean expressed a similar view.
“I know some people think that LNG Canada, if it starts on time, is bullish for AECO markets. I don’t necessarily see it that way,” he said. “I think that any incremental LNG demand is just going to spur an equivalent amount of increased Canadian production…You may see some short-term relief.” However, “what we’ve seen historically is that Canadian producers grow to fill the space. They just kind of crush their own basis.”
Canada E&P Gas Production
Leading exploration and production (E&P) companies working in the WCSB have signaled plans to increase gas output in 2023.
Tourmaline Oil Corp., Canada’s largest natural gas E&P, is forecasting 7% year/year production growth in 2023 to 2.51 Bcf/d. By 2028, the firm expects to produce 3.22 Bcf/d. Canadian Natural Resources Ltd. (CNRL) expects gas production growth of roughly 5% in 2023 versus 2022, with plans to export about 36% of output outside the AECO market. Another 36% is allocated for consumption by CNRL’s oilsands operations in Western Canada.
Montney Shale pure-play Arc Resources Ltd. is forecasting production growth of about 2% in 2023. CFO Kris Bibby told analysts during a 3Q2022 earnings call that the firm expected “very healthy pricing” through winter at the AECO hub, citing planned expansions of NGTL as a bullish driver.
However, Bibby noted that any pricing improvement would depend on the cadence of WCSB production growth. Arc’s plan is “to make sure that we’re selling as much gas as we can into the U.S. when there’s periods of congestion at AECO.”
TC, for its part, has sanctioned 1.3 Bcf/d of intra-basin capacity expansions slated to come online in Alberta by 2026, along with expansions of 300 MMcf/d and 400 MMcf/d to U.S. markets as part of the West Path and East Gate projects, respectively, on NGTL.
Gas demand on the Canada system has “never been stronger,” said TC’s Bevin Wirzba, executive vice president of Canadian natural gas pipelines, during the investor day in late November.
“In Alberta alone, we anticipate demand growth to be over 10% over the next decade,” he said.
Demand within the basin, however, is unlikely to meaningfully strengthen AECO basis differentials, according to the Calgary trader who wished to remain anonymous.
So what would need to happen?
“The supply/demand balance…in Alberta and British Columbia would have to tighten to the point where AECO maybe needs to turn off some exports and keep some gas here,” the trader said. “Or, just if the supply/demand balance tightens in general and more gas is going to leave the West Coast of Canada through upcoming LNG projects.”
