Canadian pipelines and their customers stand warned, by the United States National Petroleum Council, to expect wide swings in excess capacity and associated pressure on tolls as the North American natural gas market struggles to stay in balance through 2025.

TransCanada PipeLines is projected to have the wildest ride, as both the nation’s largest delivery system and bearer of the brunt of effects of the late-1990s introduction of competition into gas transportation north of the international border.

The stormy outlook surfaced when NPC representatives met industry leaders in Calgary for a briefing on the council’s 2003 forecast for U.S. Energy Secretary Spencer Abraham, an event hosted by the Canadian Association of Petroleum Producers. The predictions drew no quarrels from CAPP, where vice-president Greg Stringham said key issues faced by the gas industry differ mainly in details between Canada and the U.S.

The NPC’s spokesman on transportation and distribution, Kinder Morgan Inc. vice-president Ronald Brown, said “the Canadians are going to be in for a real roller-coaster ride.” The council projects that the ups and downs will be caused by large variations in supplies caused by erosion of established sources, combined with additions of replacements from the Arctic.

Between now and 2011, the NPC expects traffic on the 7 Bcf/d TransCanada system to decline by a net 400 MMcf/d even after it picks up much of the initial 1 Bcf/d due from the proposed Mackenzie Pipeline in the 2007-09 period.

Then in 2011-15, the NPC expects volumes moving on TransCanada will jump by 1.4 Bcf/d. TransCanada is projected to be the chief recipient of deliveries from the U.S. Arctic via proposed Alaska pipeline, with some volumes going into the rival Alliance system between Chicago and northern British Columbia and Alberta.

In 2015-25, traffic on TransCanada is projected to retreat again – by as much as 1.2 Bcf/d, leaving it at the end of the two-decade forecast period with a net loss on the order of 200 MMcf/d.

The outlook rests on two negative assumptions. One, that Canadians will feel the brunt of supply variations because the Alaska project’s sponsors will give up on the idea of building a new “bullet” pipeline across the continent, parallel to TransCanada and Alliance, in order to take U.S. Arctic gas directly southeast to Chicago across Canada. Two, the “plateau” of flat-to-falling capacity hit by Canadian production over the past two years marked a permanent turning point into a slow but steady decline.

In a brief interview, Brown said the NPC concluded “if you built a 4-Bcf-per-day bullet pipeline, you would have a lot of empty pipe.” He described the projection for Canadian productive capacity as a realistic outlook based on the NPC’s extensive canvass of the industry on both sides of the border.

The NPC view of the bullet line, added to the Alaska project during the last round of feasibility studies by the sponsors, is widely held north of the border, and not least at TransCanada and Alliance. But the gloomy outlook for Canadian supplies remains far from unanimous, although the decline forecast has been generated by numerous studies and has become a fixture of cases made by TransCanada to the National Energy Board for compensating rate adjustments.

On the conventional production side, Canadians are projecting a steady shift in targets to deeper, costlier, but bigger reserves than they have mostly pursued in their southern-plains producing region since the early 1990s. The level of activity is projected to keep on rising along the Rocky Mountain foothills of Alberta and northern B.C.

The latest projection — by the Petroleum Services Association of Canada, widely rated among the most reliable forecasters — calls for the deeper drilling to contribute to a record 20,400 wells in 2003 followed by 18,965 in 2004 owed to an anticipated softening of energy prices. The 2004 forecast includes 1,100 gas wells in B.C. next year, or nearly triple the 1990s average for activity there.

On the budding unconventional side of Canadian supplies, leaders of new research and field trials insist it remains far too soon to count out “tight” or difficult geological formations and especially coalbed methane.

The potential scale of coalbed methane, still largely a science or exploration project in Canada, was underlined by technical reports released during a well-attended convention of the Canadian Society for Unconventional Gas. The studies, by the Alberta Geological Survey, estimated that the plains and foothills regions of Alberta alone, harbour more than 500 Tcf of coalbed-methane “gas in place.” Water in the deposits, a critical factor in determining whether production is economic, varies depending on both geographical location and the geological formation involved.

The technical reports emphasized a fact of life that has prompted TransCanada and government forecasters to leave coalbed methane out of their projections: “It is still unknown, using current technology and based on economic conditions, what percentage of the CBM gas-in-place volume can be produced.”

Numerous producers are accelerating Canadian coal-gas exploration and field trials. Participants in the budding field range from senior producers such as EnCana Corp., Nexen Inc. and Devon Canada to a Calgary arm of a Fort Worth-based veteran of the field in the U.S. that has chalked up pioneering successes in commercial coalbed methane production in Alberta on a small scale, Quicksilver Resources subsidiary MGV Energy Inc.

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