B.C. pushing CBM development; U.S. politicians object to plans

Don Whiteley

Petroleum News contributing writer

British Columbia’s push to develop coalbed methane production to supplement conventional natural gas is running into some opposition, including from some powerful American politicians.

The U.S. State Department has advised Montana Senator Max Baucus that if British Columbia permits the development of a proposed new coal mine and coalbed methane play near the Flathead River, it will be violating a treaty.

The International Joint Commission, a bi-national Canadian-U.S. panel set up to adjudicate border disputes, ruled in 1988 that a similar proposal should not proceed.

Baucus has expressed opposition to a coal mine proposed by Cline Mining of Toronto. The mine — and an unrelated coalbed methane project — have also drawn opposition from a variety of other U.S. sources, including Montana Gov. Judy Martz.

The proposed coal mine is just eight kilometers north of the Montana border, and Americans are concerned about pollution threats to the Flathead River, which flows south from Canada and into Glacier National Park.

The coalbed methane developments have not proceeded much beyond the concept at this point. The provincial government has not yet issued any leases or permits, but it did ask for expressions of interest.

The Crowsnest coal field lies between the Elk River and the British Columbia-Alberta border and extends from southeast of Fernie to just north of Sparwood. According to the British Columbia Energy Ministry, the coal field contains in its seams an estimated 12 trillion cubic feet of gas. To put that in context, that’s more gas than the 9 tcf British Columbia currently has as proven reserves in the northeast corner of the province.

More context: the ministry estimates that the province-wide coalbed methane resource potential is 90 tcf — nearly quadruple the resource estimates for offshore natural gas. If only 10 percent of the coalbed methane is ever produced, that’s still equal to the province’s existing reserves.

The British Columbia town of Fernie — close to both the mine and the coalbed methane proposals — has already expressed its opposition to both developments.

Meanwhile, the town of Princeton in southcentral British Columbia looks like it may beat out Fernie as the first battleground for the fledgling coalbed methane business.

According to Nickle’s Daily Oil Bulletin, a Calgary-based oil industry newsletter, Petrobank Energy and Resources Ltd. is less than a year away from a pilot plant on 12,000 acres of leases on coal seams in the area. Success with the pilot plant would lead to commercial production.

The company told a Canadian Institute of Geology symposium on British Columbia gas in early May it estimates there are 321 billion cubic feet of gas in the Princeton coal seams, and the property straddles an existing gas line.

Coalbed methane production at Princeton, a half-day drive east from Vancouver, brings the oil and gas business much closer to the Lower Mainland than the traditional northeast sector in the vicinity of Fort St. John.

And the opposition to this kind of development continues to grow. Within the last month, both Petrobank and the British Columbia Energy Ministry have held public meetings in Princeton to address community concerns.

But the provincial government is very keen to encourage coalbed methane development. After introducing last year a special coalbed methane royalty rate to encourage exploration and development, the province followed up just two weeks ago with a request for proposals from the private sector for “unconventional” oil and gas projects, covering tight gas, shale gas, enhanced recovery projects, and coalbed methane.

The heart of this new enticement is a “net profit royalty regime.” In effect, the province is telling prospective developers that if they have a project that is borderline economic, they can apply for consideration of this new regime. The province defers its royalties until the project is profitable.

“If it’s a very capital-intensive project, it allows for the project to pay for itself, and once it gets to the point of producing a profit, we take the royalty,” said the Ministry’s Mark Jackson. “If we took our royalty up front, it (the project) would have a zero, or negative rate of return.”

According to Jackson, the ministry will calculate the “net profit” formula on projects as they are submitted, on an ad hoc basis. The deadline for applying is July 1, 2004.

Alberta took exactly the same approach decades ago when it was trying to encourage development of the oil sands.

And, perhaps more telling, the United States did something similar in the form of a tax incentive in the mid-1980s to encourage the development of coalbed methane plays in Colorado, Wyoming and Utah. It was wildly successful, and coalbed methane production in the United States now supplies about 8 percent of U.S. demand (or, about half the volume of gas that Canada now sends south).

Will the industry bite in British Columbia?

“There’s no question this will attract some interest,” said Greg Stringham, vice president of the Canadian Association of Petroleum Producers. “It alleviates the up front capital risk. Areas the market is pushing now are tight sands and coalbed methane. Coalbed methane is really at the emerging stage — that’s where they are looking to apply this first.”

Mike Graham, senior vice president of EnCana’s Foothills region, is enthusiastic about his company’s prospects, particularly for coalbed methane.

“We like it,” he said. “We’re looking at a bunch of unconventional plays in B.C.”