Canada's Gas Future

Much of past unconventional-gas activity in the Western Canadian Sedimentary Basin has focused on coalbed-methane development in Alberta and tight-gas plays in northeast British Columbia. Today, companies are still drilling for CBM, but to a lesser degree, due to lower gas prices. Instead, the big news in Canada is tight gas, particularly in northeast British Columbia. Thanks to the application of technology, it is one of the hottest plays in the vast, resource-rich country.

Oil and Gas Investor recently spoke with Mike Dawson, president of the Canadian Society for Unconventional Resources, about the various stages of development in Canadian gas basins, with a view to market forces.

Mostly Montney

The Montney resource play has traditionally focused on tight gas in northeast British Columbia, just west of the Alberta-B.C. border. Due to the nature of the rock, horizontal wells with multistage fracture stimulations have produced good results, with some wells yielding 5-to 6 million cubic feet of gas a day. As technology has improved, companies have expanded the play farther west, where the Montney is considered more a shale-gas type of reservoir.

Closer to the first thrust fault of the Rockies, companies like Talisman Energy Inc., Progress Energy Resources Corp. and Canadian Spirit Resources Inc. are actively drilling the Montney. Dawson characterizes these wells as closer to true shale-gas wells, with finer-grained rocks and less sand. Results vary widely, with wells coming in at anywhere from 2- to 3 million cubic feet per day up to 10- to 15 million per day. It’s expensive drilling; wells cost $5- to $10 million or more, Dawson says. But despite potentially high drilling and completion costs, companies continue to pay high land bonus prices to lock up acreage positions.

“Horizontal drilling in combination with multistage fracing has allowed the sweet spot of the Montney to expand beyond the original boundaries developed by ARC Resources Ltd. and Encana Corp.,” says Dawson.

Farther east, near the provincial border and in western Alberta, low gas prices are prompting companies to look at the Montney’s natural gas liquids (NGL) potential. Companies are adding 25 to 35 barrels of NGL per million cubic feet in their production stream, significantly impacting overall well economics. In some cases, further eastward into Alberta, the Montney play produces oil, presenting a new opportunity for “tight oil” exploration.

“There has also been a resurgence of drilling in the Deep Basin part of northwestern Alberta,” notes Dawson. “Companies are having success in drilling vertical wells in a number of Cretaceous- to Triassic-age formations that when commingled, produce attractive economics.” This success is due to fracturing technology as well as the presence of liquids.

Horn River and Lower Colorado

The Horn River Basin, which captured the attention of the oil and gas sector a number of years ago, continues to move towards large-scale commercial development. Much of the prospective land has been acquired, and activity has shifted to exploration and pilot projects. Operators are continuing to refine their well-bore designs to boost gas production while lowering costs.

“Companies are continuing to drill and complete their science experiments in terms of optimizing structure, productivity relative to cost (via multipad drilling), and fine-tuning fluids, among other efforts,” says Dawson. The major driver in developing the Horn River Basin remains new take-away opportunities, like the proposed Pacific Trails pipeline, and the proposed facility at Kitimat to export liquefied natural gas (a project of Apache Corp., Encana and EOG Resources Inc.).

Compared to the Montney play, the Horn River is likely to see a slower pace of development, as operators concentrate on infrastructure in advance of widespread field development.

Moving across Alberta, a shallow tight-gas play, the Lower Colorado, hosted some initial activity when natural gas prices were more robust. But activity has slowed dramatically due to pricing of sub-$4 per thousand cubic feet (Mcf) at the AECO Hub, combined with low production rates. Some E&P companies with well-established surface infrastructure, along with low finding and development costs, continue to operate in the region, but at a much reduced level.

Quebec

In the Utica shale formation extending into Quebec, development has slowed for a different reason. Companies such as Talisman, Questerre Energy Corp., Gastem Inc., and Forest Oil Corp. have assembled strong land positions, and entered the early stages of exploration over the past few years. But that budding activity came to a halt when the Quebec government put an interim moratorium on fracing.

“The government calls it a ‘pause,’ where efforts to understand the effects of hydraulic fracturing can be undertaken,” says Dawson. A decision is anticipated within 24 months. The level of activity that follows will be determined in part by the study’s results, but also by conditions in the North American natural gas market.

Properties producing from the Utica shale in the Quebec lowlands are ideally situated to feed gas into eastern Canada and U.S. markets, he says, and the volumes would command Nymex pricing rather than the lower AECO value. Though attractive for that reason, the play is very exploratory and lacks demonstrated commercial production. Talisman has had encouraging results from early wells, but much science and exploration work remains.

New Brunswick and Nova Scotia

Southwestern Energy Co. has a large land holding granted by the government in a greenfield play in New Brunswick, where it has been conducting seismic. The company plans to drill the first exploratory well in 2012. But as in Quebec, there is public pressure against shale-gas development in the province because of fracing fears. Dawson believes a communication and stakeholder-relations initiative will be required, as in Nova Scotia and Quebec, before exploration can move forward.

This development is in its infancy, so the upside is unknown, and will likely remain so for the near term.

Natural gas plays in Nova Scotia are smaller in order of magnitude, but there are shale-gas and coalbed-methane opportunities to be had, Dawson says. Smaller companies are exploring, but it is “early days.” Juniors wanting to develop in this province will face headwinds from low commodity prices and stakeholder relations issues.

Market considerations

Interest from northern Asia in Canada’s Kitimat LNG plant is strong, according to Janine McArdle, president of Kitimat LNG and senior vice president of gas monetization for Apache Corp.

Opinions vary as to where the natural gas market is heading. Optimists point to the lower number of dedicated gas-drilling rigs as an indicator of reduced production and higher prices on the horizon. While this trend is significant, Dawson says wells are being drilled faster and with longer laterals, bringing more gas on stream with less rig time required.

“Others talk about the steep decline rates that shale-gas production faces,” he says. “While it is true that these types of wells have steep early decline rates, it may not matter in the overall project economics.

“If a well in the Haynesville declines 70% to 80% in the first year, as long as it pays out, I am not too concerned about the decline.” Typically, the companies drilling these wells have a large inventory of well locations.

Compression and other infrastructure costs are built into infield well prices, resulting in the continued decline of overall net finding and developing costs—even in a $3.50 to $4.50 price environment, notes Dawson. Build in tight oil with associated gas as a byproduct, and the potential for additional gas production into the North American market is even greater.

Dawson believes that without material changes to North American gas demand, weak natural gas prices will persist. “Prices may be flat for a number of years until consolidation reduces drilling materially, or significant political moves happen, either for natural gas-powered vehicles or electrical power generation.” Canadian producers will continue to be challenged to operate at the tail end of the pipe in the North American market, making it difficult to compete in a price environment of $4.50 or less.

Mike Dawson, president of the Canadian Society for Unconventional Resources, says horizontal drilling in combination with multistage fracing has allowed the sweet spot of the Montney to expand beyond its original boundaries.

The LNG option

There is not much gain for Canada in trading dollars with the U.S. on a break-even basis. As a result, companies are looking elsewhere. One option is putting natural gas volumes into the Pacific Trails pipe out of northeastern British Columbia, to export to LNG facilities on the West Coast, and from there to Korea and Japan. LNG export potential is intriguing and, on its face, cost effective, unlike the current domestic market. But there are obstacles.

“There are many new LNG facilities being constructed in Australia, and Qatar continues to build additional export capacity,” says Dawson. “There is a lot of potential supply coming in, and (Asia-Pacific) may not be the unlimited market some people expect. But there is a window of opportunity for LNG export.”

That window could close if natural gas development stalls. Potential gas exporters are trying to tie up long-term sales contracts, and Canada needs to move quickly.

Dawson is confident that the pipeline to Kitimat will be built, but he hopes construction doesn’t go through delays that could negatively impact the ability to obtain export contracts.

Canada’s long-term natural gas outlook is good, but Dawson tempers this positive outlook by posing a question: How will the small, gas-centric producers survive the next few years, while North American pricing languishes and infrastructure to connect to global market opportunities is being built?

“Encana or Chesapeake can weather the storm, or deploy capital to shift to a more balanced hydrocarbon portfolio,” he says. But small companies in Alberta or Denver that would be challenged to raise $100 millionplus—opening stakes for a shale-gas player—are not as well positioned.

“The survival and sustainability of a healthy natural gas industry is at stake, and it may be that those that have, will move forward, while those that don’t will simply drift away.”