Encana Corp. has close to 11.7 million net acres from which to pick and choose for development in North America’s onshore, but the Horn River Basin in British Columbia (BC) is drawing special attention, in part because of the promise it holds for natural gas demand in the oilsands, as well as promising liquefied natural gas (LNG) exports, company officials said Tuesday.

Encana’s Mike Graham, president of the Canadian Division, shared a microphone with Kevin Smith, vice president of Canadian Ventures, and David Thorn, vice president of marketing, in a conference call in which they discussed how the company plans to optimize its quickly growing Horn River production.

Just three years ago the BC basin was thought to hold 250-1,000 Tcf of gas in place and only a few explorers — Encana, Apache Corp. and EOG Resources Inc. among them — had placed a development bet on whether the remote region contained enough gas to make infrastructure development cost-effective. Today gas prices may be low but a lot more producers, large and small, have taken stakes in the basin and the estimated gas in place is considered much higher. Even with persistently low gas prices, Encana sees nothing but upside.

“The Horn River resource base is enormous, highly accessible and will certainly play a large role in North American and even global gas supply in the years to come,” said Smith. The basin is in one of North America’s richest areas for natural gas but it is far from U.S. markets, which holds some advantages, he noted.

Encana in the mid 2000s quietly amassed acreage in the basin and to date has accumulated more than 278,000 net acres of about two million acres available, making it the third largest net acreage holder in the play.

This year Encana expects to end the year producing about 95 MMcf/d from the Horn River, which is only a small portion of Encana’s total North American production of about 3.5 Bcf/d. However, the basin’s gas output could reach 5 Bcf/d by 2020 if processing capacity is installed, said Smith.

In April, May and June Encana’s total output averaged around 85,000 Mcfe/d. By the end of 2011 the company, which partners with Apache on a portion of the play, expects to be producing 95,000 Mcfe/d.

To reduce costs and improve efficiencies, Encana is using its gas manufacturing system, which it perfected in the Haynesville Shale and has since been adopted across the industry. Under its “resource play development hub” approach, the Calgary-based producer drills multiple wells from a single pad and uses concurrent completion operations to create a minimal environmental footprint, Graham explained.

“Today the Horn River has taken the form of multi-well pads with as many as 16 horizontal wells with up to 28 completion stages in each horizontal well.” Encana and Apache together are producing about 300,000 Mcfe/d on a “combined gross raw basis,” he said.

Graham has called the Horn River play the “best” shale play in North America. And Smith said the play’s economics compare favorably to its touted U.S. counterparts.

“The Horn River has high initial production rates relative to other North American shale gas resources plays but it also enjoys a generally lower decline rate, particularly in the first year of production,” said Smith. The multi-pad drilling technique is important not only from an environmental perspective “but wells on this 16-acre surface area actually are drilling something close to six square miles of reservoir. That helps us to optimize the location of all the equipment we need.”

Encana and Apache increased the number of hydraulic fracturing stages on their wells in the basin from three in 2007 to “as many as 30 this year,” said Smith. And with the bump in the number of fracturing stages on each well, there’s also been “corresponding increases in production.”

It’s not just gas in the shale that Encana covets. The producer is eyeing a plan to triple its liquids output from not just Horn River but its extended BC properties and in the Deep Basin of Alberta over the next few years, said Graham.

“Encana is well positioned in the Deep Basin of Alberta and British Columbia, where we plan to increase natural gas liquids production from 10,000 b/d to 30,000 b/d in the next couple of years by putting in ‘deep-cut’ facilities. The first of this should come on in the fourth quarter of this year, thereby increasing Encana’s liquids production by around 5,000 b/d.”

For the new supplies of gas expected to flow from the Canadian properties, Encana is optimistic that the liquefied natural gas (LNG) export facility being planned for Kitimat, BC, which would carry gas to Asian markets. The KM LNG facility is owned by affiliates of Apache (40%) and EOG Resources Inc. (30%); Encana gained a 30% interest in the facility and associated pipeline earlier this year.

Encana, which is Canada’s largest gas producer and behind only ExxonMobil Corp. in the United States, has been slammed by low gas prices. Earlier this year the independent abandoned a plan to double by 2015 its gas production to 7 Bcf/d. The Kitimat project would help expand its gas markets, said Thorn.

The partners will make a final decision about whether to move forward with the export terminal in early 2012, said Thorn. If it’s a go, the first LNG shipments could begin in 2015, he said. The KM LNG facility as designed would be able to export in two 700 MMcf/d trains up to 1.4 Bcf/d at full capacity. The terminal and associated pipeline have been on the drawing board in different partnership configurations for more than two years.

Even without Asian exports, Horn River gas is expected to supply the burgeoning oilsands industry in Alberta, which Encana estimates will take another 1.3 Bcf/d by 2020. But a bigger source of long-term demand is in fuel-starved Asian markets. The partners now are awaiting completion of a front-end engineering and design (FEED) study, which is expected to be done by the end of this month.

“Before we proceed, we need some clarity on the project economics,” said Thorn. The FEED study now under way would give the partners an idea of the cost economics to ship gas to Asian markets. KM LNG already has an approved environmental impact certificate in place, he said, and an export license may be in place as soon as this month.

The partners also are completing plans for the Pacific Trails Pipeline, which would link the LNG terminal to Spectra Energy’s gas processing complex in Summit Lake, BC, said Thorn. The 287-mile line would have 1 Bcf/d of capacity.

KM LNG has the support of the Alberta and BC energy departments, with no reservations. But the partners have to keep their eyes on a smaller, competing proposal, BC LNG Export Co-Operative LLC, that also is working its way through regulatory approvals and lining up customers.

Until now the KM LNG partners have kept quiet about export marketing plans. However, Thorn disclosed that negotiations, led by Apache, are under way “with up to six buyers…Deals are expected to be completed in the first quarter…” Volumes, he said, are being negotiated to supply a two-train facility.

“We expect to see very strong demand in Asian markets by 2020,” said Thorn. Demand growth is forecast to be about 65 Bcf/d by 2020, “dominated by China and India making up 55% and 12% of demand, respectively…” Several Asian countries also will have growing demand, he said, but China represents the largest potential source of natural gas demand supported in part by LNG imports with a target of 8%.

“The LNG gap between Asian supply sources and demand increases from less than 1 Bcf/d in 2010 to about 24 Bcf/d in 2020. If it’s not constrained by supply, potential demand requires an additional 15% by 2020,” Thorn said. The “spread between Asian pricing and North America looks very supportive” for natural gas, but until the studies are completed and contracts are in place, he said it was too soon to provide an actual cost breakdown.