After almost two years of study, a provincial committee has recommended offering Alberta's budding coalbed methane developers only a limited financial incentive to grow faster. Instead of copying generous inducements which helped launch coal gas in the United States and that British Columbia has adopted, the Alberta proposal is a temporary grant for field research.
A "multi-stakeholder advisory committee," known as the coalbed MAC, urged Alberta Energy Minister Greg Melchin to enact a short-term royalty cut for pilot gas wells into the still little understood Mannville coal zone.
While the formation carpets much of central Alberta, it is steeped in salt water and its permeability or capacity to flow gas is highly variable. The Mannville is believed to harbor more than half of the province's potential for up to 500 Tcf of coalbed methane.
The committee majority urged the adoption of "an appropriate level of royalty reduction for a period of up to five years to encourage the drilling of saline CBM wells in the Mannville for the purposes of acquiring information." A minority of environmental representatives on the MAC opposed royalty changes, saying if any energy supplies deserve help it is renewable sources such as wind power.
The incentive should be a "pilot-type program" that would generate public data on the economics and geological and technical aspects of operating in the vast coal formation, the committee said. The recommendation is partly a reaction to an emerging pattern of keeping such information private as a matter of competitive advantage in Alberta.
Technology and coal seam information are closely guarded trade secrets at the lone commercial Mannville development, launched a week ago 75 miles northwest of the provincial capital of Edmonton by Trident Exploration, Nexen Energy and Red Willow Production Co.
Trident chief operating officer John Koch described the company as "officially neutral" on financial incentives. Trident, a private firm heavily backed by American investors and with a leadership team that also draws on U.S. coalbed methane veterans, has put four years and tens of millions of dollars into taking the lead in Mannville development.
The committee's emphasis on limiting the aid reflects the key role of gas in Alberta's finances. Of an estimated C$9.6 billion (US$7.6 billion) in energy resource revenues collected by the provincial treasury in the 2004-05 fiscal year that ended March 31, C$6.5 billion (US$5 billion) or nearly 70% came from gas royalties.
No incentive at all was recommended for the most widespread form of coalbed methane development in Alberta so far, projects in the shallow and dry Horseshoe Canyon formation. In a review of the emerging sector, the MAC said "based on the great similarity to other shallow gas wells in southeastern Alberta, the royalties currently applied to the Horseshoe Canyon-Belly River and other dry CBM developments appeared to be appropriate to the resource." The committee said it also "considered the difficulty in distinguishing between coal- and sandstone-sourced gas from the same well . . . it would be impractical to try to differentiate between the two sources for royalty purposes."
Most committee recommendations focused on refining Alberta regulations to eliminate any chance of a repetition of Wyoming's notorious environmental headaches owed to early CBM operations that disposed of semi-fresh water on the land surface.
The Canadian province's environment department has strictly controlled water handling for generations. Current projects in coal seams steeped in salt water follow strict regulations requiring produced brine to be kept separate from the environment. Mandatory procedures include re-injecting CBM waste water into deeper formations known to be briny already. Coalbed methane production involving fresh water is prohibited until a new regulatory regime is developed.
The Canadian Society for Unconventional Gas continues to lobby for wider royalty reductions for coalbed methane. The group hopes the province will recognize there are "fundamental differences" -- led by water handling costs -- between coalbed methane and conventional gas, CSUG chairman Kin Chow said. "Some companies are holding back" until the royalty system is adjusted to recognize the extra costs of coal gas, Chow said in an interview. However, "it's not a unified opinion."
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