B.C. beckons Alberta's royalty-shy producers

Incentives favour unconventional gas resources, such as shale, just as Alberta is considering raising royalties

By Don Whiteley
The Globe and Mail
Sep 24, 2007

VANCOUVER -- Spooked by proposals to significantly increase petroleum royalty rates in Alberta, Calgary's oil and gas producers are looking to British Columbia as a safer haven for their investments.

And a set of incentives introduced by Victoria appears to be paying off already, based on the last two petroleum lease auctions conducted in B.C.

"The [Alberta royalty] proposal is fairly sweeping," said Dave Pryce, Western Canada vice-president for the Canadian Association of Petroleum Producers (CAPP). "But assuming they [the Alberta government] do make some changes in line with the report, it can only help B.C. There's a real potential on the gas side for people to look at B.C. now rather than Alberta."

Gary Leach, executive director of the Small Explorers and Producers Association of Canada, had a similar reaction when asked whether hikes in Alberta oil and gas royalties will help neighbouring jurisdictions.

"Yes it will," Mr. Leach said. "I know there are already some investment reports out saying dump companies that are 100-per-cent or hugely exposed to Alberta."

A blue-ribbon panel concluded in a report brought down this past Tuesday, that Albertans have been shortchanged on revenue from the province's energy resources and recommended substantial increases in royalties paid by companies that extract them.

According to Mr. Pryce, B.C. has over the last few years worked hard to implement royalty incentives aimed at encouraging the industry to pursue non-conventional energy sources such as tight gas, coal bed methane, and the new kid on the block - shale gas.

The jewel for the province was EnCana Corp.'s decision to pursue what are now the Greater Sierra and Cutbank Ridge tight gas projects in northeastern B.C. (Tight gas is the term used for a resource locked in particularly dense rock.) In 2003, EnCana spent $418-million tying up leases for Cutbank Ridge in what stands as the largest land sale ever completed in B.C.

But the second- and fourth-largest land sales in the province's history were completed in the past two months, with the September sale of oil and gas leases bringing in $265.2-million and the August sale generating $149.7-million. Interest in shale gas dominated both sales, according to B.C. Energy Minister Richard Neufeld.

"You just know that when they pay that kind of money, they've got something," he said. "That's good for us. Our geologists tell us that the potential resource from shale gas is 250 trillion cubic feet, and that's just in B.C. Even if we recover just a portion of that, it's huge."

The two areas of interest are the Horn River Basin, which Mr. Neufeld says is the largest shale gas play in Canada, and the Cordova Embayment. In 2007 alone, companies have spent $40-million on leases in Cordova and $240-million over two years on leases in Horn River.

Gas trapped in shale is not a new resource, it has been overlooked in Canada in the past because it is difficult to produce compared with gas from other types of reservoirs. But significant volumes of natural gas are produced from gas shales in the United States.

"It's huge because it's shale," said Vic Levson, assistant executive director in the resource development and geoscience branch, Ministry of Energy Mines and Petroleum Resources. "It's a completely new target.

"Five years ago people would have laughed you off the street if you said there'd be a huge land sale in shale."

The successful bidders in the two land sales have not been identified because of confidentiality provisions, but Mr. Levson confirmed that they include several of the major Calgary-based energy companies.

Commercial shale gas production of about 375 billion cubic feet a year, or 3 per cent of U.S. domestic supply, comes from Texas, Colorado, New Mexico, Illinois and Michigan. A study done for the B.C. Energy Ministry says that about 20 per cent of the shale gas in place can be economically recovered, compared with 75 per cent in conventional reservoirs.

According to Mr. Levson, what is attracting industry to B.C.'s shale gas potential is both the quantity of the gas in place and the capacity of the shales to be fractured so the gas can be produced.

"We've got some fantastic, very thick shales," he said. "The organic content [used to calculate the gas volume] is phenomenal, and the shale is brittle so it will fracture."

Mr. Levson said industry testing to date is still confidential, "but I'm assuming they are getting pretty positive results or they wouldn't be laying down the dollars they are."

CAPP's Mr. Pryce concurs with that assessment: "In a North American market when gas prices are relatively low right now, if you see those kinds of leading indicators, that bodes reasonably well."

Interest in B.C. shale gas comes as drilling in the province is in serious decline because of chronically low natural gas prices. The province faces a 42.2-per-cent drop in drilling activity this year, and expectations are the decline will carry into 2008.

The Petroleum Services Association of Canada (PSAC), in its July survey of Canadian drilling activity, predicted an average decline of 24 per cent in Western Canada, but nearly double that rate for B.C. Well completions in B.C. are expected to drop from 1,375 a year in 2006 to 795 a year by the end of 2007.

"The main problem is the drop in commodity prices for natural gas, and B.C. is primarily a gas play" said PSAC president Roger Soucy.

Mr. Pryce sees the shale gas interest as much longer term, and designed to take advantage of the province's incentives.

A new profit royalty program introduced this year is aimed at reducing royalty payments in the early stages of development for expensive, and risky, projects like coal bed methane, tight gas, and gas from shale.

After a project is approved by the Ministry, royalties will be calculated on a sliding scale ranging from 2 per cent of revenue at the start of production until all capital costs have been recovered, rising to 35 per cent of profit (or 5 per cent of revenue) after capital costs plus 105 per cent have been generated.

"It's a mechanism to share the risk up front with the Crown," Mr. Pryce said. "We pay a relatively low royalty rate until we've paid for the cost of the project and then the rate jumps. It helps manage the risk and encourage the investment."