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Providing coverage of Alaska and northern Canada's oil and gas industry
May 2008

Vol. 13, No. 20 Week of May 18, 2008

Alberta gets the brush off

Royalty increases taking toll on investment in province despite higher gas prices

Gary Park

For Petroleum News

Any notion that the current resurgence of natural gas prices might camouflage the fallout from Alberta’s royalty increases has been quashed by Canada’s two largest gas producers.

EnCana and Canadian Natural Resources, which produce 3.7 billion and 1.54 billion cubic feet of natural gas per day respectively, a high percentage from Alberta, aren’t budging from their tough resistance to the royalties that take effect in 2009.

CNR has delivered one of the sharpest setbacks yet to government and support industry hopes that a two-thirds rise in commodity prices will open the door to a flurry of fresh activity.

Company President Steve Laut said that until high prices are realized at the wellhead CNR won’t change its gas drilling strategy in Alberta.

He noted that although gas has climbed this year to $10 per thousand cubic feet from $6, $3 of that $4 increase will go directly to the Alberta government under its new royalty framework.

Laut said Alberta’s high costs and small reserves per well mean gas prices would probably have to top $12 to provide a base for the economic drilling of medium-depth wells, but at prices of $6-$12 Alberta royalties are a disincentive to drill.

“When conditions are right (in Alberta) we can grow gas when we choose,” but an uptick in prices is likely to benefit British Columbia more than Alberta because of that province’s royalty regime, he said.

Laut noted that the slump in Alberta government land sales is a signal of future activity levels.

Growth in oil projects

For now CNR is not troubled because of its rapidly growing conventional heavy oil, thermal oil and oil sands mining projects, its land holdings in British Columbia and Saskatchewan and its overseas operations, he said.

Laut said CNR has a “deep inventory of gas locations that can add significant value in a relatively quick and efficient manner” when conditions improve.

For now, a company presentation showed it has sharply curtailed its gas plans for most of Alberta. In the Deep basin it now projects an ultimate 2,000 wells, down from 3,100 before the royalty increases; conventional plays in the Western Canada Sedimentary basin, heavily concentrated in Alberta, have been trimmed to 2,100 wells from 3,335; and the Doig Shale has been lowered to 200 wells from 275.

Its major focus is on the Hatton area of southwestern Saskatchewan, where the drilling potential is estimated at 2,000 wells, and the Mann coalbed methane play of Alberta and British Columbia’s Muskwa shale, each 800 wells.

EnCana has taken a similar hard line against Alberta, refusing to make any changes to its 2008 capital budget.

That largely puts paid to a late April research note by investment dealer Peters & Co., which said larger Canadian gas producers were ready to direct more of their 2008 cash flow into drilling, naming CNR and EnCana as candidates, along with Devon Canada and ConocoPhillips.






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