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Alberta Revises Royalty Regime, Cites 'Unintended Consequences'

With other Canadian provinces touting large natural gas discoveries, Alberta has backtracked on its royalty regime changes and now will offer substantial breaks for deep oil and gas drilling.

The province last Thursday unveiled two royalty programs, one for oil and one for natural gas, that would provide "adjustments" within the new royalty regime framework that is scheduled to take effect on Jan. 1, 2009.

A provincial task force last September recommended that Alberta impose higher oil and gas royalties beginning in 2009 on new and existing projects to increase revenue by 20% a year (see NGI, Sept. 24, 2007). The news resulted in a huge backlash, with several of Alberta's top producers and many of its junior operators saying they would cut back their exploration efforts in the province and shift funding to other areas (see NGI, March 10; Oct. 29, 2007; Oct. 8, 2007).

Alberta Energy Minister Mel Knight, who announced the new royalty programs in Calgary, said that when provincial authorities looked at its many oil and gas plays in the province, "what we felt was at risk was something in the neighborhood of C$500 million plus" for uncollected royalties. However, because the producers countered that they could not keep up with higher operating expenses and more taxes in Alberta, the suggested royalty regime could have led to a result of "no drilling, no production, equals no royalty."

Knight declined to address whether there was industry pressure to revise the original program. The province did not "bow" to industry pressure, he said, but it was addressing "the unintended consequences" while still achieving "the necessary levels of investment and production...This government is not willing to accept that risk [of unintended consequence] when it comes to Albertans' jobs and livelihood and the royalties that these programs help to generate."

Producers that drill natural gas wells more than 2,500 meters deep would receive royalty credits. Gas royalties would be calculated based on the sum of vertical drill depth and all laterals to encourage more development of coalbed methane (CBM). More laterals could "significantly lessen land use and the environmental footprint of CBM development," according to the province.

Deep gas well credits are expected to cost the province an estimated C$200 million a year for five years, or around C$1 billion. Credits for oil wells drilled deeper than 2,000 meters would cost the province an estimated C$37 million a year for five years.

However, the loss of revenue would be offset by increased exploration, said Knight. Alberta could see about C$1.5-2.0 billion more from deep oil and gas revenues over the coming 10 years if the program is enacted, and taken together, the net benefit could be C$510 million in royalties over the decade.

Most of the "new" deep gas well exploration would be in the Alberta Foothills, which are part of the Rocky Mountains. Deep gas wells account for about 5% of all of Alberta's gas wells, but they accounted for 27% of gas production between 2002 and 2007.

Alberta's new programs likely would help large producers, but the Small Explorers and Producers Association of Canada said few of its members would receive any help. The association vented its frustration over royalty increases allowed on shallow wells in picked-over fields, where geological targets are shrinking and costs per unit of production are on the rise.

Meanwhile, the Canadian Association of Petroleum Producers, which represents about 90% of Alberta's gas output, said prices and details of the incentive scheme as they apply to every well would determine whether the industry response turns out to be as aggressive as the government predicts.

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