Driven by high prices, depleted storage, demand growth forecasts and signs that conventional production has at best peaked and at worst begun slipping, Canadian natural gas suppliers are hunting a new generation of reserves that can be put to use fast.

With completion of a Mackenzie Valley pipeline at least five years away and development stalled offshore of Nova Scotia by drilling disappointments, coalbed methane has surfaced as the prime target. It also has remained elusive.

Tapping coal seams commercially remains an almost entirely theoretical prospect in Canada, where activity is still largely confined to about a dozen pilot projects and an embryo production development on the eastern plains of Alberta. Although the field has spawned a line-up of conferences and a new industry association, the Canadian Society for Unconventional Gas, the outlook is hazy and sometimes hotly contested.

In a toll case being heard this month by the National Energy Board, TransCanada PipeLines Ltd. insists that the prospects for coalbed methane north of the international border are too shaky to be taken to the bank. In making a case for an accelerated depreciation rate that the Canadian Association of Petroleum Producers is fighting as liable to cost shippers C$250 million (US$167 million) a year, TransCanada says it cannot count on coalbed methane to replace depleting conventional gas production that threatens to create permanent vacant capacity on its 7 Bcf/d east- and U.S.-bound mainline.

TransCanada maintains that the time needed for Canadian coalbed methane production to reach even relatively modest levels in the range of 500 MMcf to one Bcf per year will be measured in years rather than months.

The pipeline told the NEB “the production profile of the unconventional resource has different characteristics than the conventional resource and is highly dependent on the rate of technological improvement and success at locating ‘sweet spots’ — that is, areas in which the permeability is high enough to make production economic.”

The permeability, or ability to flow gas, of Canadian coal seams remains a topic of considerable debate, with some specialists including staff of the Geological Survey of Canada observing that they tend to be much less conducive to production than deposits in the U.S. TransCanada sides with the geological conservatives, saying it can hardly conceive of Canadian coalbed methane production approaching current U.S. levels in the foreseeable future.

“It seems highly unlikely that unconventional gas will approach 8 Bcf/d or 50% of the total Western Canada Sedimentary Basin production in the next 15 to 20 years,” the pipeline told the NEB. “The reality is that unconventional gas has very low permeability, very low well initial production rates and requires substantial levels of drilling to develop substantial new supply.”

This dour view is far from universal, however. The launching pad for a coalbed methane policy under development by the Alberta Department of Energy, a 70-page discussion paper, rates the province’s coalbed methane production potential as up to triple its remaining conventional reserves of 43 Tcf. “The outlook for the development of a sustainable coalbed methane industry in Alberta is positive,” the document insists.

Alberta, source of 80% of Canadian gas production, also harbors much of the coal within economic reach. The discussion paper estimates the province’s endowment of coalbed methane at 410 Tcf, including 60 Tcf in the foothills of the Rocky Mountains and 350 Tcf beneath the plains farther east. Recoverable reserves are estimated at up to 135 Tcf. The province is far from projecting the findings on limited permeability at scattered experimental sites across the entire portfolio of coal deposits.

With help from an industry-based advisory committee, the province is considering a range of policy initiatives including “potential economic mitigation strategies” — incentives, akin to the tax breaks that kick-started coalbed methane development in the U.S.

The energy department paper observed “the major economic hurdles associated with the development of a coalbed methane industry in Alberta relate to expectations of low productivity, significant upfront costs and long payout periods.” Discussions with industry to date pointed to “need for a fiscal and economic framework which recognizes the specific incremental operating and capital costs associated with coalbed methane production.”

No promises are being made and no official target date has been set yet for enactment of a coal-gas policy or adoption of incentives. But the provincial government relies heavily on royalties set in the 20% range for the four-fifths or more of gas production that comes from Crown leases.

Strong motivation to move the process along has been provided this heating season by unanimous reports from the NEB, the Alberta Energy and Utilities Board and the Canadian Energy Research Institute. All say the chief gas-producing province’s conventional supplies have peaked and possibly already entered the natural decline phase, unless the industry develops a taste on a large scale for deeper, remoter, costlier drilling and succeeds in making new geological discoveries.

As the coalbed methane policy review continues, the elements include an industry consensus reported by the preliminary paper: “A fair and reasonable incentive should be considered which would encourage the industry to drill, for a sufficient time period, to gain the necessary technical understanding of the potential for producing coalbed methane in Alberta.”

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