NGI The Weekly Gas Market Report
Alberta’s share in a projected Canadian gas drilling recovery will be slow, the province’s Energy Resources Conservation Board (ERCB) said. The number of successful wells completed could even drop for a second straight year before an anticipated turn for the better rolls around, the agency predicted in its latest annual review of Alberta reserves.
Flat prices, worsened by rising costs and unfavorable exchange rate trends, knocked Alberta field activity down 17% last year to 10,796 wells from 12,932 in 2006, the board reported. This year, successful well connections could drop again to 9,800, the ERCB added. The anticipated recovery in Alberta — home to about four-fifths of Canadian production and drilling — is forecast to start showing in 2009, with the well count rising to 11,000.
An annual average of 12,500 wells is projected over the rest of the ERCB’s forecast period through 2017. The 2007 activity drop left year-end Alberta reserves inventory at 38 Tcf, down about 5%. Annual production of 4.8 Tcf remained near historic highs last year. The ERCB continues to project a slow but steady decline in production, due largely to natural aging of Alberta’s best fields dating back to the 1950s. The current forecast calls for an annual conventional production decline rate of 3.3%.
The province’s bottom-line net production decline rate is expected to be 2-3%, depending on the development rate of replacement unconventional supplies led by coalbed methane. Production from coal seams is forecast to grow from an almost negligible share to 16% of Alberta’s total over the next 10 years. No estimates are made for next-generation shale gas, although an Alberta Research Council partnership with industry has begun working on production techniques and such “tight” deposits are becoming targets of field trials just across the provincial boundary in northeastern British Columbia.
Supply effects of the drilling trends remain unclear, with some industry participants such as TransCanada PipeLines suggesting production declines could be slower than widely anticipated.
The transporter has observed that the well counts fall short of telling the whole industry story, saying they could mask qualitative changes of a shift in drilling priorities over to costlier and much more prolific deep targets in the foothills of the Rocky Mountains. Shallow plains wells cost as little as C$310,000 a piece. Foothills wells, involving frontier-style access issues like building roads as well as longer drilling times in more complex geology, run into the C$2.5 million area.
For the immediate future the ERCB anticipates that no easily measurable change in the industry pattern as the majority of producers by head count — although not necessarily by output — continue to avoid the heavy lifting and costs of drilling for big targets.
“Much of Alberta’s gas development has centered on shallow gas in southeastern Alberta, which contains more than half of the province’s producing gas wells but only 20% of the 2007 production,” the ERCB observed. “Shallow drilling will continue to account for a large share of the activity in the province over the next few years.”
The current state of western Canadian supplies remains a puzzle, with some of the data murky at best. A storage survey by FirstEnergy Capital Corp., for instance, found that “May 2008 was the strongest injection month of this decade.” By the end of May, total western Canadian gas in storage stood at 294 Bcf, or 65% of estimated total capacity of 453 Bcf.
FirstEnergy, which continues to belong to the forecaster majority expecting Canadian production declines, suggests the big storage injections were due to declining export sales and injections by merchant storage operators taking advantage of favorable prices to top off storage facilities.
“We still expect available gas supply will keep trending lower for the remainder of 2008 at a minimum,” FirstEnergy said, adding that receding productivity will be amplified by rising consumption at growing thermal oilsands extraction operations.
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