Canadian Gas Market Must be Rebalanced: Panel
The near-term viability of the western Canadian natural gas market depends on a combination of supply rebalancing and new takeaway capacity to serve markets inside and outside Alberta, according to speakers at a February 7 round table hosted by Natural Gas World.
The round table, Monetising Gas in Western Canada, heard producer concerns surrounding dramatically lower prices in Alberta than are available elsewhere in North America and pipeline capacity expansions that are on the horizon that should alleviate some of those pricing concerns over the next few years.
Darren Gee, CEO of Peyto Exploration & Development, one of the largest dry gas producers in western Canada’s Deep Basin, said prices available at the AECO trading hub in Alberta are well below the level needed for producers to break even on their full cycle supply costs, even though most producers have dramatically lowered those costs in the last few years.
“Most producers are realising a price below $2/gigajoule (GJ) (US$1.66/mn Btu), but just to break even, the average producer needs about $2.40/Gj,” Gee said. “But nowhere on the forward strips for natural gas do we see a price anywhere close to $2.40.”
Looking beyond Alberta offers little comfort either, he said. Even assuming producers could get capacity to markets in eastern Canada or the US at regulated tolls, the price for that gas netted back to Alberta, using current Nymex prices, is still only a little over $2/Gj.
“In order to get a price that is going to allow producers to break even on their full cycle costs and potentially at least hold the basin at this level we are going to have to rebalance supply and demand in western Canada,” Gee said. “Which means we have to shrink supply and we have to increase local demand.”
Shrinking supply means cutting capital expenditures in Alberta, halting most drilling programs and letting natural reservoir declines kick in, much like the moves the industry took between 2008 and 2012, when AECO prices collapsed from more than $7.50/Gj to around $2.50/Gj.
“We lost about 4bn ft3/day of supply during that period, and that’s about what we need to contract today in order to match Canadian demand,” he said.
The other side of the equation must see demand growth, and there is potential for that to happen as well, Gee said. Coal-fired power generating stations will be switching to gas in the coming years as Alberta’s emissions reduction initiatives take hold; new petrochemical facilities will bring increased demand; and there is still additional oil sands production from committed investments that will push demand higher.
The only alternative, Gee said, is taking on US producers in the North American market, where massive supply increases from shale basins in the northeast Appalachian region and huge volumes of gas produced in association with tight oil production in the Permian Basin of Texas are battling for the same markets as Canadian producers.
“That’s a challenge, because to compete in those markets we have to get to those markets, and to do that we need more pipe and lower tolls because we’ve got to be able to realize a little more revenue on the producer side,” he said. “More pipe and lower tolls, the basin can grow; same pipe and same tolls, the basin declines – there is just no other alternative.”
But Tracy Robinson, senior vice president and general manager, Canadian natural gas pipelines for TransCanada, said Canadian producers, acting in concert with pipelines like TransCanada, Alliance and others, can compete for those markets.
“But we need to be responsive, and we need to act fast,” she said, noting that the Marcellus and Utica basins in the Appalachian region of the US northeast alone are expected to bring 19bn ft3/day of new supply into the North American market in the next decade.
TransCanada is already the key conduit for western Canadian producers to reach domestic and export markets: in 2017, it delivered nearly 5.1bn ft3/day to markets in Alberta and BC; nearly 2.6bn ft3/day to markets in eastern Canada and the US northeast; about 2.2bn ft3/day to the Pacific Northwest and California; and another 1.66bn ft3/day to markets in the US Midwest.
Current expansion projects, she said, will add 2.2bn ft3/day of capacity, with half heading east to the TransCanada Mainline and the rest split between capacity to serve intra-Alberta markets (about 550mn ft3/day) and capacity to serve markets in the western US (about 650mn ft3/day).
“But we need more, and we are today sitting down with our producer customers to determine the best and most efficient way to do more.”