Cheap and plentiful U.S. shale natural gas is putting pressure on Western Canadian producers in U.S. and Eastern Canada markets, with one industry association expressing fears that Canadian production may fall by half by 2030.
Hopes that West Coast LNG would create huge new markets for British Columbia and Alberta producers were dashed when Petronas canceled its 19.2 megatonnes a year Pacific Northwest LNG project last month. Still, there are a few rays of optimism for innovative, low-cost companies.
“The Canadian Association of Petroleum Producers’ expectation is that natural gas exports to the United States will decline as U.S. shale gas production grows—perhaps to about half their current levels by the end of the next decade,” is how Mark Pinney, CAPP manager of natural gas markets and transportation, described the gloomiest scenario in an email.
Western Canada’s Achilles Heel is geography.
“The bad news side is that it takes cost of production plus cost of transport to get to market, and it’s the latter where B.C. and Alberta gas has a disadvantage,” says Blake Shaffer, an economics PhD. candidate at the University of Calgary. “Shipping on TransCanada to get the product to eastern markets often costs as much as the price of the commodity itself [and this month, many times more]. U.S. shale gas is advantaged in its proximity to market demand and potential for increased LNG and Mexican exports.”
B.C. and Alberta producers are being pressured in Eastern Canadian markets by cheap gas from the Marcellus and Utica basins. After an abandoned attempt to negotiate fixed-price 10-year tolls late last year, TransCanada lowered its rates on the Mainline system ( to Eastern markets, where it will soon compete with the Rover pipeline, currently under construction, that will transport 3.25 Bcf/d of Marcellus and Utica gas). The lower tolls may not be enough, according to Shaffer.
The news is not all gloomy. Shaffer says the Montney/Duvernay in northeastern B.C. has both estimated reserves and cost of production that rival even the best U.S. plays.
“We are seeing deeper and longer wells with heavier fracks deliver greater production per well at lower cost. The technological learnings from the U.S. are being transferred and applied here. On a cost of production basis, the Montney [in northeastern B.C.] is as competitive as anything out there,” he said in an interview.
Changes to Alberta oil sands SAGD production—substituting solvent to dissolve bitumen instead of burning gas to create steam—are expected to reduce steam-oil ratios over the next 10 to 15 years. But lower natural gas consumption per barrel of oil will be offset by the expansion of oil sands output from 2.6 million b/d to 3.7 million b/d by 2030. Alberta Energy estimates aggregate gas demand will grow by 5.4% a year until 2026.
And Canadian producers are thus far able to compete in U.S. markets. Maria Sanchez, manager of energy analysis for Drillinginfo, said natural gas imports from Canada averaged 6.1 Bcf/d in 2016 and 5.8 Bcf/d so far this year. She expects a 15% to 20% further decline over the next five years, which is a significant improvement from the 75% drop her firm was forecasting last year.
“There are still some declines expected, but not as dramatic,” she wrote in an email. “The main reason for this is that the Canada gas has basically nowhere else to go, so they continue to price themselves lower in order to compete with U.S. gas.”
Lower priced Canadian gas and growing U.S. LNG exports and pipeline exports to Mexico are putting pressure on American gas and “could create an opportunity for Canadian gas to backfill market demand in North America in the event U.S. supply growth is not as robust as currently anticipated,” said Pinney.
Canadian companies are already looking to American LNG producers. Calgary-based Seven Generations Energy, one of the lowest-cost Canadian producers, in March netted the company a supply agreement with Cheniere Energy.
“Whatever is being shifted out of the southern U.S. for exports needs to be backfilled, either by U.S. supplies or Canadian supplies so there’s lots of opportunities to get that gas to market,” GMP FirstEnergy director of institutional research Martin King told the Financial Post. “The U.S. is coming up short of gas supply. They will buy it and they will pay more for it as a necessary consequence.”
Some relief may also be coming from the Western Canada market. Pinney says the phase-out of coal-fired power generation in Alberta and Saskatchewan will create an opportunity for Canadian gas.
“If all of the coal-fired power generation capacity in western Canada was to be replaced by natural gas-fired generation this would represent an incremental market opportunity of 1.5 billion cubic feet per day,” he said. “Although some of this generation capacity is slated to be met by renewables such as wind and solar, because these are intermittent sources of power they need to be backstopped by other sources of generation and natural gas provides a reliable source of supply to backstop the market.”
An Alberta government committee is expected to recommend later this month that the province expand its subsidy program that supports new petrochemical development.
“Global methanol consumption has been rising, particularly due to increases in Chinese demand, and Western Canada is blessed with abundant methane supplies, a feedstock for methanol, and would be an attractive location for an end user looking to diversify its sources of methanol supply,” according to Pinney. But there are no firm plans in place beyond two plants already subsidized under the existing program.
Other positive trends that could affect Western Canadian gas, according to Shaffer, include a likely continued downward trend in production costs, a further proposed significant reduction in TransCanada Mainline tolls and declining Marcellus volumes. He says headwinds could include possible Ontario climate policy that would reduce or eliminate natural gas consumption, and the possible construction of the Alberta to the Maritimes Energy East pipeline, which would include the conversion of some gas pipeline to oil.
“The best Alberta and B.C. gas producers can do at the moment is continue to drive down costs and work with pipelines to make delivered gas competitive,” Shaffer concludes.
Leasing hot spots, improved drilling metrics and more reveal some silver lining in the cloud hanging over Midcontinent producers.
Pin Oak Energy closed a transaction with a Shell affiliate to acquire roughly 43,000 acres prospective for Utica Shale development in northwestern Pennsylvania.
Private E&P LLOG Exploration and Spain’s Repsol agreed to collaborate on deepwater development in the U.S. Gulf of Mexico plus an asset exchange of the Leon and Moccasin discoveries.