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Shifting Supply Spurs Change in Canada

Plans to combine northern Alberta and British Columbia (BC) into a natural gas common market are coming together on schedule, thanks to simultaneous regulatory and industry decisions.

The National Energy Board (NEB) opened the door to the combination by handing down a historic ruling that will transfer to its jurisdiction TransCanada Corp.'s half-century-old Nova grid in Alberta. The switch, which ends a tradition of fiercely defended exclusive control by Alberta, enables TransCanada to build Nova extensions across the provincial boundary into BC.

TransCanada requested the jurisdictional move and the Alberta government agreed not to resist, saying times have changed since it chartered Nova as an instrument of provincial economic development policy. Declining supplies in Alberta, growth in BC and prospects of arctic gas pipelines eventually being built made the transfer necessary in order to preserve the role of the province and Nova as a North American-scale gas trading hub, Alberta officials explained.

The pipeline extensions that TransCanada intends to build into BC will include a service known as NIT, short for Nova Inventory Transfer, which enables transactions anywhere on the 24,000-kilometer (15,000-mile) Alberta network.

Just hours before the NEB handed down its ruling, TransCanada reported that it is ready to proceed with the second of its two Nova extensions after successful completion of an open-season auction of delivery capacity on the proposed Horn River Pipeline (see related story). Shippers signed up for an initial 378 MMcf/d of service, or enough to justify building a 155-kilometer (100-mile) Nova extension to the Horn River Basin shale gas region near BC's boundary with the Northwest Territories.

The line will be laid using pipe up to a jumbo size of 36 inches in diameter for an estimated C$340 million (US$272 million). Producers and TransCanada alike expect Horn River supplies to grow steadily as the industry masters new shale gas production techniques being imported from Texas and adapted to northern conditions.

"We expect to add future capacity to the line as the right opportunities present themselves," TransCanada president Hal Kvisle said in announcing the open season results.

TransCanada previously sold transportation service contracts for 1.1 Bcf/d on its first proposed BC extension, the Groundbirch Pipeline into a tight and shale gas production area farther south known as Montney. The 78-kilometer (50-mile) line is forecast to cost C$250 million (US$200 million).

The NEB jurisdictional ruling enables TransCanada to file construction applications in time to hit completion targets of 2010 for Groundbirch and 2011 for Horn River.

Kvisle pointed to northern BC as a "tremendous, largely untapped source for unconventional natural gas." Producers voted with their feet to start tapping the deposits on a large scale by spending an annual record C$2.66 billion (US$2.1 billion) on BC drilling records in 2008.

Additional plans for an expandable new processing complex near Fort Nelson confirm that producers are gearing up for sustained development on a large scale in northern BC. The jumbo project, called the Cabin Gas Plant, is sponsored by an eight-member consortium of EnCana Corp., Apache Canada, Devon Canada, EOG Resources Canada, Nexen Inc., Quicksilver Resources, Stone Mountain Resources and a partnership of Imperial Oil with its majority owner ExxonMobil.

The plant construction schedule calls for completion of a first, 400 MMcf/d phase in late 2011, then five more identical stages. "Each subsequent phase is expected to be installed as production from the Horn River natural gas basin comes on-line and demand for processing increases," consortium leader EnCana told BC environmental authorities in initial regulatory filings.

BC's Horn River Basin contains 600 Tcf of natural gas and 10-30% of the astronomical total can be economically tapped with current technology, the producer group estimates in regulatory filings. The gas saturates a fossil Devonian-era shale reef about 180 meters (590 feet) thick underlying 6,200 square kilometers (2,480 square miles) of northern bush and muskeg swamps at a depth of 2,700 meters (8,800 feet). Even the forecast minimum Horn River production of 60 Tcf exceeds Alberta's total remaining 39 Tcf in conventional reserves by 54%.

A further part of the BC package is in preparation as the provincial government reviews the first applications for use of a new net-profit royalty system intended to encourage shale gas development. The program, a gas counterpart to the Alberta oilsands royalty regime that helped ignite a plant construction boom in the province's northern bitumen belt, sets rates at a token 2% until development costs are paid off. Rates then rise, but royalties will only be applied against revenues net of production costs rather than in traditional fashion to gross sales income.

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