Improved prices and better access to markets do not appear to have allayed investor concerns that natural gas traded at Canada's benchmark hub could crash to sub-zero prices once more.

The price difference between TC Energy Corp.'s benchmark AECO C hub in southeastern Alberta and the U.S. standard Henry Hub in Louisiana averaged 31 U.S. cents/MMBtu year-to-date as of Nov. 20, according to data compiled by the Petroleum Services Association of Canada. Prior to the 2019-2020 winter heating season, that discount was much steeper, and Alberta prices had consistently trailed the Henry Hub by US$1/MMBtu to US$2/MMBtu since 2017, according to the U.S. Energy Information Administration.

The steep differential evaporated in October 2019 after the Canada Energy Regulator adopted new rules that allow TC Energy to divert gas to storage when its mainline system, the largest in Canada, is constrained.

Gas producers have started to regain favor with investors who shied away from the sector after a major service outage on TC Energy's NOVA Gas Transmission Ltd. gathering system sent AECO prices into a nosedive in May 2018. The AECO spot price dropped to negative 1 U.S. cent/MMBtu on May 4, 2018, as gas backed up in the Nova system. That event was instrumental in the Canada Energy Regulator's amendment to shipping rules to allow diversions to storage.

Still, many investors are not convinced that the resulting higher AECO spot prices, which had averaged C$2.207/MMBtu in 2020 as of Nov. 27, are safe from future interruptions. The jitters returned in a sudden widening of the AECO-Henry Hub differential in early October.

"It appears investors are still skittish on the AECO market, as we received numerous inbounds last week on the spot basis blowout to approximately US$1.60/MMBtu, which generated flashbacks and concerns from investors as the wounds from the past couple years remain fresh," analysts at Tudor Pickering Holt & Co. said in an Oct. 12 note. "We remind investors that capacity expansions on the [Nova] system have relieved the bottlenecks and volumes still remain about 0.6 Bcf/d below prior highs."

Canada's gas industry is seeing a revival as North America replaces coal-fired power generation with the cleaner-burning fuel. The coronavirus pandemic, which pummeled oil markets, has highlighted steadier demand for gas in times of crisis. TC Energy and rival Enbridge Inc. have invested heavily in their Canadian gas infrastructure in anticipation of more power generation — including backstopping interruptible renewable sources such as solar and wind — and expanded exports of LNG. TC Energy operates Canada's largest gas export pipeline network, while Enbridge is the nation's biggest gas utility owner. Both companies have acquired large competitors in the U.S. in recent years to bolster their North American gas transportation services.

In addition to being able to access points across Canada, the U.S. and Mexico, producers in the liquids-rich shale regions that straddle the Alberta-British Columbia border have increased ability to tap NGL markets outside of the continent. A consortium led by Royal Dutch Shell PLC has a large LNG export project under construction on British Columbia's northern coast. The project is one of a pair of survivors amid almost two dozen proposed liquefaction plants.

Propane exports

AltaGas Ltd. managed to bring back one of the scuttled LNG export sites as a propane export terminal in 2019 utilizing its deepwater port, rail access and proximity to Asian markets. The plant has seen a steady increase in shipments to Asia, touching a record 42,700 barrels per day in the third quarter of 2020. The Ridley Island Propane Export Terminal, or RIPET, is expected to reach 50,000 b/d of throughput in 2020 and has an ultimate capacity of 80,000 b/d. The success of RIPET was partly why AltaGas decided to boost its ownership stake in Petrogas Energy Corp., which owns an NGL export terminal in Ferndale, Wash.

Increased production of propane and other NGLs, particularly condensate used in oil sands transportation, lowers the production cost associated with the dry gas that is left after the chemicals are stripped. That in turn leaves more, cheaper gas available for sale through AECO and other North American hubs. AltaGas expects to be able to use its expanded assets to capture an increased share of the NGL export and domestic condensate markets.

"We've always talked about additional volumes at RIPET and obviously optimizing Ferndale with very, very little capital investment that we feel that we can capture," AltaGas Executive Vice President and CFO James Harbilas said on the company's third-quarter conference call. "There is also other volume growth within the basin and additional product offerings that we can bring to producers, potentially condensate solution, that we're excited about."

Despite some bumps in the fall season, the Tudor Pickering Holt analysts anticipate that the AECO-Henry Hub price spread will become more stable throughout the winter heating season. At AECO and across most northern hubs, heating demand usually kicks in around the beginning of November. Still, the analysts noted that prices across the winter of 2020-2021 could lead to a wider spread than prices in the forward market indicated in October.

"Once winter demand picks up and storage constraints are no longer a concern, we expect the tight setup for 2021 to begin to show and basis to normalize," the analysts said. "From this perspective, we see no structural issues to support a sustained basis blowout into 2021, but we do see risk to wider price spreads than the forward strips are pricing in."