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Alberta Extends Driller Incentives

June 29, 2009
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The Alberta government last Thursday granted a one-year extension of two temporary natural gas drilling incentive programs but postponed decisions on introducing any permanent regime changes.

Provincial Energy Minister Mel Knight said the expiry date on a royalty credit for drilling and a new well incentive will be set back by 12 months to March of 2011. The schemes give producers credits against royalties of C$200 (US$174) for each meter of new drilling, and set a ceiling of 5% on royalties for new production.

The schemes were forecast to cost the province C$1.5 billion (US$1.3 billion) in foregone royalties and to fuel a drilling revival when they were first announced last winter (see NGI, March 9). But dropping gas prices since then have undermined all such projections by sharply cutting both field activity and the value of royalties. Rates automatically drop as prices fall. Industry officials say market conditions are the biggest factor affecting drilling in Alberta, where activity fell into a deep slump despite the incentives.

The announcement was timed to give gas producers a chance to incorporate the incentives into budgets for the 2009-2010 drilling season and possibly increase numbers of wells planned. In Canada, field activity peaks during the coldest months because the industry relies on taking advantage of frozen ground for moving and operating heavy equipment.

"This extension responds to market challenges facing oil and gas exploration in Alberta," Knight said.

The principal challenge identified by producers and the government alike is low prices on a glutted market across Canada and the United States. Industry sources in Calgary predict that the incentive program extensions are bound to encourage drilling but will not fully counter fundamental supply and demand conditions.

Most benefits are expected to be scooped up by gas producers that have exceptionally attractive targets in their drilling rights lease portfolios. In those cases the royalty incentive schemes top up the economics of projects that stay attractive even in spells of low prices. Anderson Energy, for instance, predicts that all its drilling costs will be covered and initial production royalties will be substantially reduced as it embarks on a joint venture with ConocoPhillips Canada to tap a rich central Alberta shallow gas deposit known as the Edmonton sands with up to 1,000 wells.

Alberta Premier Ed Stelmach, in a two-day flurry of political spin prior to Knight's announcement, said the province recognizes the main underlying cause of the soft market is surging unconventional supplies led by shale gas in the U.S. But unlike British Columbia, where a northern branch of shale production is developing, Alberta has no special royalty regime tailored to the new technology.

"We're not immune to what's happened around the globe," Stelmach said. "This is all about people keeping their careers, whether it be engineering...the rig workers, the motel operators, people that repair tires and trucks in small communities. It's all based on how we can support further activity in the oil and gas industry."

Under the current program, the province offers royalty credits to producers of all sizes for new wells drilled through March 31, 2010. Alberta also is levying a 5% royalty rate -- its lowest rate -- for the first year of production for any well that begins to produce during the period.

The well incentive program now in effect also provides a maximum 5% royalty rate for the first 12 months of production, up to a maximum of 50,000 bbl of oil and 500 MMcf of natural gas. For example, as long as production caps were not reached, a well producing on April 5, 2009 would be eligible through April 5, 2010; a well producing on March 25, 2010 would be eligible through March 25, 2011. The two programs together were expected to amount to around C$1.5 billion in royalty savings for producers in the next year. In addition to the drilling incentives, the province planned to invest C$30 million to begin an orphan well fund for the clean-up of inactive oil and gas wells.

Stelmach's latest pledges to producers included an acknowledgment that there is no higher-stakes game for the provincial treasury because gas royalties are the provincial government's largest single revenue source. Stelmach, echoing Canadian industry leaders and analysts, said the province's current gas prices and revenue troubles are not going away because the cause is not financial and energy market cycles, but rather new technology being used to increase gas supplies in the United States and other Canadian provinces.

Describing the gas market as "very depressed" across North America, the premier predicted "there are dark clouds ahead if we don't respond." A provincial energy strategy released nearly a year ago raised the possibility of royalty breaks for unconventional production -- especially shale gas and coalbed methane -- and the premier's statements Wednesday appeared to signal that the government believes the time to make a move has arrived.

The Alberta treasury has been feeling the pain from increasingly glutted gas markets and the resulting erosion of prices for more than three years. The total royalty take -- normally 20-30% of gross wellhead revenues, calculated with a complex formula driven by prices and well production volumes -- has dropped by more than half.

After peaking at C$8.4 billion (US$7.3 billion) in 2005-2006, annual Alberta gas royalties for fiscal years ending every March 31 tumbled to C$6 billion (US$5.2 billion) for 2008-09. In the current 2009-10 budget year the government officially estimates that gas royalties will be C$3.9 billion (US$3.4 billion). But that guess was made early this year, when provincial forecasters still felt confident that the 2009 average price would be C$5.50/gigajoule (US$5/MMBtu).

On top of slipping prices, Alberta is plagued by natural production declines in conventional fields that have amplified the effects of soft prices. In a recent annual state-of-the-industry report, the province's Energy Resources Conservation Board (ERCB) predicted that output would fall by 6% this year and then erode by an annual average 4% through 2018. The ERCB predicts that fledgling coalbed methane production, and eventually shale gas development, will partially compensate for the decline but makes no guesses by how much. Coalbed gas remains in its infancy in Alberta and there is no known commercial shale production yet.

Knight set a target of this fall to complete Alberta's promised "review of overall competitiveness" including regulation, taxation, costs and labor as well as the provincial royalty regime.

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