While growth prospects remain up in the air, earlier reports of accelerating gas production decline rates in Canada were exaggerated, the National Energy Board has been told. A new, more optimistic consensus is emerging from a ongoing industry debate over the supply outlook.

This fall before the NEB, TransCanada Corp., Canada’s chief gas transporter, continued to seek increased income through a variety of financial adjustments partly on grounds that it faces growing “supply risk” or prospects of running empty sometime in the future. The situation has prompted reviews of supplies and forecasts by shippers, especially the Canadian Association of Petroleum Producers (CAPP).

Recent conclusions have proven that the previous consensus forecast — that western Canadian supplies were peaking and poised to enter annual declines of 2% or more — was overly pessimistic, according to a CAPP report conducted by Gilbert Laustsen June Associates (GLJ), the Calgary-based geologic engineering and energy economics consulting house.

The drama of the supply situation was tied in part to the meteoric rise and fall of a spectacular discovery in northeastern British Columbia that is now becoming better understood. “The unique characteristics of the extraordinarily prolific Ladyfern Slave Point A Pool in B.C. have exaggerated the implied apparent decline,” GLJ said in written testimony submitted to the NEB.

“Relative to the Western Canadian Sedimentary Basin average, the reserve life index of the Ladyfern discovery was very low,” GLJ said in the reserved language of the professional expert witness. In layman’s terms, Ladyfern turned out to be a bubble that popped faster than anybody could have predicted.

“Ladyfern volumes peaked in March of 2002 at 633 MMcf/d of raw gas or 3.6% of total WCSB production and declined by June of 2004 to 76 MMcf/d or 0.6% of total WCSB volumes.” The B.C. discovery was so big that its rapid rise and fall “accounts for almost all productivity gains and losses between 1999 and 2004. Basin supply excluding Ladyfern has remained flat in that period,” GLJ testified.

At the same time, western Canadian production demonstrated more resilience than anticipated by forecasts made during the Ladyfern episode. Excluding effects of conservation rulings in 2003 and earlier this year by the Alberta Energy and Utilities Board, output has grown. By GLJ’s count, first-half 2004 WCSB production virtually matched output a year earlier. The 2004 performance would have improved on ’03 if the AEUB had not decided to shut in a host of northeastern Alberta gas wells found to jeopardize future “in-situ” or underground oilsands extraction projects, GLJ said.

Although gas producers succeeded in blunting effects of the ruling in a prolonged technical duel among engineers and geologists, the policy has so far shut in 80 MMcf/d of production.

TransCanada contested CAPP’s use of the GLJ material in a lengthy procedural wrangle before the NEB this week. But other experts also stepped forward to present the board with a brighter portrait of the western Canadian supply outlook.

The idea that the Canadian basin’s productivity will run down any time soon is just too pessimistic in light of gas price trends and the consensus view of its potential, added another expert witness for CAPP, prominent U.S. specialist Andrew Safir.

The consensus, shared by TransCanada, is that the ultimate potential for conventional gas reserves is about 275 Tcf. That leaves 137 Tcf awaiting production, not counting the widely estimated 167 Tcf of virtually untapped coalbed methane available using currently foreseeable technology, plus 61 Tcf thought to exist in the Mackenzie Delta-Beaufort Sea region.

TransCanada projections that it needs increased revenues to compensate for anticipated shrinkage in gas traffic suffer from a flaw evident in all current formal supply forecasts, Safir suggested. “The predictive accuracy of any model is based on the historical data available.”

Canadian forecasts have rested on bleak prices of C$1-$3 per GJ (US$0.80-$2.40) fetched by Alberta and B.C. production throughout the 1990s. Canadian prices took far longer to rise than their U.S. counterparts. Until 2001, and completion of Alliance Pipeline, a shortage of long distance pipeline capacity caused an artificial supply glut in Alberta and B.C.

Canadian prices rose rapidly as the new delivery capacity opened and held their gains by consistently exceeding $5 (US$4) since the end of 2002, Safir pointed out.

“The present and future represent a new era for gas prices. In my view, this discontinuity of gas price levels over the historic base is likely to result in a systematic underestimate of the natural gas supply response in most forecasting models,” Safir said in written testimony to the NEB.

Provided the resource endowment involved is large enough to respond to increased industry activity, Safir said supply projections need to be adjusted to obey “a very fundamental economic principle which states that supply curves are more elastic over time. That is, for a persistent increase in price, the amount supplied will increase over time. On the basis of this principle, it would be expected that a fundamentally higher price for natural gas in the WCSB would effectively lead to the application of technologies that would extend the producing life of the basin.”

Translation: tell me what the price is and I’ll tell you what the recoverable reserves are. The economic law described by Safir is being obeyed well before the economists’ models formally record all the changes in industry behavior, CAPP told the NEB.

The association, whose members do more than 90% of Canadian gas production, said the North American market has to recognize it will not be possible to repeat the steep growth rates that doubled annual Canadian production to more than 6 Tcf between the mid-1980s and late ’90s. But that does not mean supplies will shrink or entirely stop growing, CAPP emphasized.

CAPP pointed to the C$7 billion (US$5.6 billion) Mackenzie Gas Project, rapid acceleration of Canadian coalbed methane activity from scattered experiments only two years ago to a forecast 3,000 commercial wells in 2005 alone, and increases in deep drilling along the eastern fringes of the Rocky Mountains.

“They are the developments one would expect to see given the long-term demand for natural gas in North America,” CAPP told the NEB. “They are occurring in response to the now-clear, sustained price signal from the market. Investment levels by the producing sector are very high. The market works. The supply is responding.”

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