Prospects of prolonged natural gas gluts have prompted a recommendation for Canada’s National Energy Board (NEB) to start preparing for hearings on costs of shutting down an industry cornerstone: TransCanada Corp.’s Mainline from Alberta to Ontario, Quebec and border crossings into the U.S. Midwest and Northeast.

The request surfaced during lengthy testimony by representatives from the Canadian Association of Petroleum Producers (CAPP) at NEB hearings on TransCanada proposals for overhauling the Mainline’s tolls and services (see Daily GPI, July 31).

Producers testified to the continuing gas surplus as markets have barely begun to burn off surpluses that have gutted prices across North America, say Canadian producers.

“I call it the crash scene,” NEB chairman Gaetan Caron said in a blunt statement on the nub of nearly 50 days of hearings and a year of collecting documentary evidence on the Mainline’s troubles. “Nobody wants to go to dress for the funeral, but we’ve been talking about it.”

CAPP President David Collyer said, “we’re not at that point, and we don’t think we should be preparing for the funeral. But having said that, it’s not outside the realm of possibility that we’ll end up there, and I think it makes sense for all of us to think about what the options are to deal with that.”

All concerned in the marathon case agree on the cause of the potential crash: a plague of excess capacity on the Mainline that has more than doubled tolls on the gas still flowing in it, to C$2.24/gigajoule (GJ) (US$2.35/MMBtu) from C$1.03/GJ (US$1.08/MMBtu) in 2007. (U.S. and Canadian dollar at par; 1 MMBtu is 1.05/GJ).

All also agree on the force behind the half-empty Mainline’s deteriorating ability to recover by attracting traffic: the emergence of rich shale gas supplies, especially in U.S. deposits close to former big markets for Canadian exports but also as growing competition for Alberta production in Ontario and Quebec.

CAPP told the NEB that potential routes to recovery are visible on the economic horizon but the industry has yet to make much progress on steering the new courses.

Among numerous scenarios being examined before the Canadian board, the gas supplier association described “the not-so-good case” as the easiest one to see continuing. “We’re probably in the environment we’re in for an extended period of time on the not-so-good case,” said David Thorn, Canadian gas marketing vice president of Encana Corp., the country’s top producer and one of the biggest supply developers in U.S. fields.

Thorn identified the “unquestionably” most promising and largest route to recovery to be replacing coal as boiler fuel for thermal power stations, especially in the United States. But displacing coal will take time to make a difference even if encouraging action favoring gas as a cleaner energy source emerges among U.S. regulators, led by Washington’s Environmental Protection Agency, he added.

“We still view North American supply as being very plentiful, even with a high degree of displacement,” Thorn said. “We don’t think we return to an environment where gas prices are much beyond the $5-6/MMBtu range.”

Like their U.S. counterparts, Canadian producers see overseas exports of surpluses as liquefied natural gas (LNG) as the second major route for clearing away the North American supply glut. “LNG is a fantastic market opportunity,” said Real Cusson, senior marketing vice president of Canadian Natural Resources Ltd. (CNRL), Encana’s closest rival for the top spot among the country’s producers.

But a flaw has shown up in tanker export projects as their details are exposed by regulatory applications: high costs, said Cusson. He described LNG development as “terribly expensive.”

“The numbers that we have seen from the [project] proponents are in the range of $10 to $12 billion of investment for each billion cubic feet of capacity,” Cusson said.

The CNRL executive described the LNG export terminal lineup forming on the Pacific Coast of British Columbia, where two projects have NEB export licenses and a third has filed an application for one, as requiring astronomical financing. “If we had, say, five of these projects completed on the West Coast, we would be looking at $50 to $75 billion to be invested. Now that’s a pretty considerable sum.”

While awaiting power generation demand and LNG terminal construction to materialize, CAPP is urging the NEB to take a first step toward preventing the TransCanada Mainline’s potentially lethal problems from spreading onto the producers’ western home turf.

They called on the board to reject a key item in the toll and business restructuring proposal called the Alberta system extension (ASE). The scheme would cut the Mainline’s tolls by redrawing the pipeline map to shorten its length for financial and ratemaking purposes.

The ASE plan seeks to expand TransCanada’s Nova pipeline grid in Alberta to cover all of BC and Saskatchewan as well. The financial transfer would also include a Saskatchewan leg in TransCanada’s 2 Bcf/d Foothills export route to the United States. Nova and Foothills are currently regulated separately from the Mainline and each other.

CAPP has estimated that the ASE spells added costs to producers of $400-500 million per year. CNRL Chairman Murray Edwards added that allowing the scheme to go ahead would give TransCanada an avenue for piling onto gas shippers yet more costs if the Mainline’s problems worsen.

Edwards emphasized that shippers that use the Nova system often do not have Mainline transportation contracts because the Alberta grid provides connections to all long-distance pipelines that carry gas out of the province. He predicted that if TransCanada succeeds in redrawing the pipeline financial map, “you would have 200-odd [Canadian] producers who would all of a sudden be faced with not just immediate costs, but also the potential risks could be foisted on them.”

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