Ontario power producers eye U.S. shale gas supplies

Union Gas among players keen to link new basins to old markets

October 19, 2011

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Illustration by Jeff Kulak

The precipitous drop in long-haul gas shipments along TransCanada Corp.’s Mainline warranted no mention in a summer deal that saw a suite of power plants in northern Ontario change hands. Yet the pitch and churn of North American natural gas markets is something Boston-headquartered Atlantic Power Corp. – repeating the experience of exploration and production companies everywhere – must now confront after acquiring Capital Power Income LP from Edmonton-based Capital Power Corp. in July.

The deal ended a lengthy strategic review undertaken by Capital Power Corp. Atlantic picked up Capital Power’s 29 per cent share in the limited partnership, acquired by predecessor Epcor Utilities Inc. in 2005 as a vehicle for accessing equity markets. Among the 19 power assets to change hands are four combined-cycle natural gas-fired plants commissioned in the 1990s, located at North Bay, Iroquois Falls, Nipigon and Kapuskasing.

The plants generate a portion of their power using waste-heat drawn from compressor stations on the Mainline. Despite a new tariff proposal that would lower the cost of shipping gas between Alberta and Ontario to $1.41 per gigajoule, down from the interim cost of $2.08 per gigajoule, overall tolls on the steel artery have climbed 60 per cent since 2007 because of falling throughput. As production accelerates from shale basins located closer to densely populated markets in southern Ontario and regions east of the Mid-continent, the reduced flow rates mean northern Ontario plants that rely on waste heat can’t generate as much electricity.

Between 2009 and 2010, Capital Power Income LP watched revenue generated from its Ontario plants drop sharply, from $15.4 million to $6.4 million, as a direct result of lower throughput on the TransCanada conduit. The pain was amplified because long-term power purchase agreements signed with the Ontario Electricity Financial Corporation contained no provisions to pass through toll increases to end users, limiting operational flexibility. The plants are “captive with a capital C,” says David Butters, executive director with the Association of Ontario Power Producers, or APPrO for short. “They’re stuck there, and there’s no way to bring gas in other than to back haul it up.”

The predicament is a small sample of a broader issue APPrO argues is causing Ontario natural gas-fired generators undue financial pain. The agency, whose members represent 90 per cent of the 19.3 gigawatt-hours of gas-fired electricity produced in Ontario in 2010, says pipeline infrastructure in the province must be adapted to provide access to production from new basins as long-haul shipments from Western Canada dwindle. But who will pay for any system overhauls is an open question.

APPrO members say they are already bearing the brunt of expenses associated with shifting reliance from western gas supplies to other regions. “What’s happening is that in this transition from [western Canadian] flows into Ontario across the northern line, and all these changes in flow in North America, is that Ontario power producers are essentially subsidizing that change by having to absorb those on their bottom line,” Butters says. “At some point it threatens the economic health of those companies.”

The northern plants acquired by Atlantic Power are part of a class of Ontario facilities called non-utility generators, or NUGs. They were originally commissioned in the 1990s under power purchase agreements spanning 15 to 50 years for a total generating capacity of roughly 1,652 megawatts, most it fueled by natural gas, biomass or hydro power. Some of the gas procurement contracts that underpin those agreements – many of them tied to long-haul shipments originating at Empress, Alberta – are set to expire over the next decade.

Negotiations with the Ontario Power Authority are underway to see those agreements either renewed or replaced with something new, but a speedy resolution is unlikely following an October election. “There’s a lot of murkiness post-election around what the electricity sector institutional structure looks like,” Butters says. “How that would impact all these decisions is a question mark.”

Larger generators in the southwestern half of the province can expect to draw on new shale gas supplies via the Dawn trading hub if Union Gas Ltd. is successful in courting new supplies from shale basins in the Mid-continent, the Gulf Coast region and even as far as the U.S. Rockies. Located 35 kilometers southeast of Sarnia, the Union Gas Dawn Facility is a meeting point for 10 major pipelines, including TransCanada’s Great Lakes Transmission System, a 3,400-kilometer pipe that connects to the Mainline at the Manitoba-North Dakota border and continues through Michigan to Dawn.

Union Gas is proposing a more direct route to supply the Ontario market by connecting with emerging shale basins through Michigan. Its proposed Dawn Gateway project would link Gulf Coast shale gas and new supplies to Dawn using a combination of existing and new infrastructure. Startup of the pipeline has been delayed until at least November 2012.

“People who live in northern Ontario are still subject to services that are assuming that gas is coming pretty much entirely from the Western Canadian Sedimentary Basin,” says energy consultant John Rosenkranz, a participant in last year’s Natural Gas Market Review led by the Ontario Energy Board. There’s no reason to stop companies from taking advantage of new supply sources, he notes. “It’s just a matter of making sure the utility services keep up with changes in the market.”

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