Alberta, source of four-fifths of Canadian natural gas production, has reached its natural upper limit as a supplier and its industry will have to scramble to maintain current output, the National Energy Board says.

In a status report on the nation’s gas resources, the NEB concluded a long-range trend has established itself. About 80,000 wells drilled in Alberta between 1990 and 2000 generated only a “marginal” increase in estimates of the province’s resource endowment because the industry ran out of new discoveries.

The board raised its forecast of the province’s ultimate gas potential by 3.5% to 207 Tcf from the previous official rating of 200 Tcf. Even that modest change remains subject to revision back down to lower calculations of other agencies such as the Canadian Gas Potential Committee, depending on results of further review under way in co-operation with the Alberta Energy and Utilities Board.

The NEB said “the larger impact of that drilling has been a change in the ratio of undiscovered to discovered gas,” a sign of age marking the end of the exploration era and the beginning of a time of harvesting the results.

“In 1992, the proportion of undiscovered was 39%, while in the 2004 assessment it is 30%, indicative of a maturing basin with limited opportunity for significant additional growth in the ultimate potential.”

Unlike some of its counterpart producer regions of the United States, Alberta also has little to gain by letting the industry more easily into environmentally sensitive areas such as its eastern slopes of the Rocky Mountains. The NEB calculated the industry is being denied access only to about 2.5 Tcf of potentially marketable Alberta gas reserves.

The off-limits total could rise to four Tcf in Alberta, but the industry will have itself to blame if that happens. The province’s rapidly growing cities are threatening to seal away 1.5 Tcf of reserves beneath new residential subdivisions unless the industry accelerates production from fields discovered long before the onset of urban sprawl. Such efforts are under way especially in the Calgary area, but continuing access to the old fields on the fringe of the Canadian gas capital is complicated because the reserves are “sour” or laced with lethal hydrogen-sulphide that raises alarms in communities at considerable distances from the wells.

More than half of Alberta’s ultimate potential has been produced. The new NEB calculations peg the remaining marketable gas left in Alberta at 94 Tcf. The NEB suspended judgement on prospects for northern British Columbia, suggesting the relative freshness of its gas fields leaves open possibilities that the outlook there could be much brighter than in Alberta.

In BC “there may be opportunities to find larger pools both in the plains region and in the foothills.” Recent discoveries in formations not previously believed to harbor gas in BC “could have a significant impact on the total ultimate potential of BC,” the NEB said.

While official estimates of BC’s ultimate gas potential still stand at an old figure of 51 Tcf with 35 Tcf still left to produce, the NEB and the BC Oil and Gas Commission are reviewing their forecasts in light of the new drilling results.

But the optimism about BC is offset by glum conclusions about the newest branch of the Canadian gas industry offshore of Nova Scotia. After recent drilling disappointments in the Sable Island region, the NEB wants no part of optimistic industry forecasts early in this decade that the region might harbour 50 to 100 Tcf.

The board adopts conservative forecasts: a total of about 23 Tcf, including 8.8 Tcf beneath shallow waters offshore of Nova Scotia and 14 Tcf in deep water plays. The potential of the area remains largely a guessing game: “The results from drilling programs taking place in the upcoming years will be critical in indicating the potential level of production from the basin.”

The same goes for as yet untapped and relatively unexplored areas offshore of Newfoundland and BC, which remain far from reach due to geographical remoteness plus regulatory and political obstacles. The Mackenzie Delta-Beaufort Sea region continues to be rated as having potential for 61 Tcf even on the basis of currently limited knowledge, but the timing of production and future additional exploration remains up in the air as efforts to advance the Mackenzie Gas Project continue.

Also still up in the air are prospects within Alberta for development of unconventional supplies including coalbed methane, shale gas and “tight sands” deposits. “Timing and the amount of gas production from those sources remains unclear, although it should be noted that commercial production of coalbed methane has recently started in Alberta,” the NEB said.

The NEB’s reading of industry trends was confirmed in a new survey of current performance by FirstEnergy Capital Corp., a Calgary investment house that makes a specialty of tracking drilling results.

By FirstEnergy’s count, “the extent of the effort toward drilling natural gas targets in western Canada has been nothing short of monumental.” The investment house estimates nearly 15,000 gas wells were completed in the region last year and that the number will rise to 16,000 this year.

But field receipts by western Canadian pipelines dropped by 433 MMcf/d or 2.5% to 15.97 Bcf/d in 2003. In 2004, FirstEnergy predicts that all the drilling activity will only restore about half of last year’s losses with the industry raising production by 200 MMcf/d. Nearly half the gain is expected to come from a forecast 1,000 coalbed methane wells.

“All this information actually supports being very cautious on supply and remaining bullish on natural gas prices,” FirstEnergy said.

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