The management team at unconventional natural gas giant Encana Corp. has raised its cost outlook for both the United States and Canada and said last week the labor and supply markets are as tight as they’ve ever been. However, the company is fighting back by using cutting edge technology to drill wells in less time and at a lower cost.

Even though Encana ditched its Canadian oilsands and refining assets when it spun off Cenovus Energy Inc. two years ago the Calgary producer is still impacted by the high price of oil, said Mike Graham, who runs the Canadian division.

“The labor market in Western Canada is definitely tight again, similar to where it was in 2007, early 2008, when we had the big run-up in oil prices,” he told financial analysts during a conference call last Thursday.

Canadian costs are expected to be 4-6% higher from a year ago, but in the United States costs will be 10-12% higher, said Jeff Wojahn, who runs the U.S. operations.

CEO Randy Eresman said the company is fighting cost creep — and persistently low gas prices — by cutting out the middle man in many instances by buying its steel and fuel and striking long-term service agreements. Encana also is using state-of-the-art technology in its gas fields.

Encana has “adapted to this prolonged period of soft natural gas prices by taking meaningful steps and applying advanced technologies to manage costs over the long term as we pursue margin maximization on all of the natural gas that we produce.”

For instance, in its Haynesville Shale operations, Encana has reduced well drilling times in the last year by 20% to 40 days, “and a number of wells this year have been drilled in 35 days.” In addition, “to counter the high demand and inflationary rates for well completion equipment, we have established long-term, efficiency-based contracts with four new, dedicated completions crews.”

By “applying effective logistics management and leveraging Encana’s demand, we have reduced our cost of commodities by self-sourcing steel, sand and fuel. These are proactive cost management programs that we expect will result in significant and ongoing cost savings.”

Encana’s “integrated supply chain approach also helps eliminate bottlenecks and optimize cycle times,” said the CEO. “We now have 15 rigs fueled by natural gas, about one-third of our current drilling complement, generating fuel savings of between $300,000 and $1 million per rig per year, depending on the rig’s size and fuel system. While industry cost inflation this year is expected to average about 10%, we expect our inflation rate to average approximately half that level, which we expect will be more than offset by improvements in efficiencies.”

The company is the largest gas producer in Canada, but it has quietly built substantial onshore unconventional positions across North America. During the latest quarter Encana established two more sizable land positions in prospective liquids plays. In western Alberta the company has accumulated more than 365,000 net acres in the Duvernay play, “where preliminary drilling results by Encana and other operators show significant potential,” the company said. Two more Duvernay exploration wells are planned for this year. In Mississippi and Louisiana, Encana also has captured more than 250,000 net acres of the Tuscaloosa Marine Shale, and plans to evaluate the play’s potential later this year.

“Both of these plays are in their early days, but we are encouraged by our exploration results to date,” said Eresman. “Duvernay and Tuscaloosa are just two of a handful of exciting opportunities that we are pursuing on the more than 2.1 million net acres we hold with strong potential for liquids production.” Included in its portfolio are the Niobrara formation in Colorado, the Collingwood Shale in Michigan and land positions in the Alberta Deep Basin and the Montney formation in Alberta and British Columbia.

The company still plans to sell $1-2 billion of noncore assets by the end of this year. In June the company ended talks with a subsidiary of PetroChina International Ltd. over a proposed joint venture to tap gas in the Cutbank Ridge region of British Columbia and Alberta (see NGI, June 27). Eresman said legal reasons prevented him from detailing the reasons why the partnership was scuttled. However, “competitive marketing joint venture opportunities on Encana’s extensive undeveloped lands in its Cutbank Ridge resource play will commence this summer.”

The producer also still has plans on the table to sell midstream and upstream properties across Canada and the United States, including the northern portion of its Greater Sierra resource play, midstream assets in the Cutbank Ridge, an interest in the Cabin Gas Plant in the Horn River Shale and midstream assets in the Piceance Basin of Colorado.

In the final three months of this year Encana’s long-awaited Deep Panuke gas project offshore Nova Scotia (NS) also is scheduled to begin production, with output ramping up to about 200 MMcf/d. Offshore work to be completed this fall includes commissioning the operational systems, hooking up the four production wells and connecting production facilities to the 176-kilometer pipeline that will deliver natural gas to shore at Goldboro, NS.

About half of Encana’s gas production — 1.8 Bcf/d — is hedged through the end of this year at an average New York Mercantile Exchange (Nymex) price of $5.75/Mcf. About 2 Bcf/d of expected 2012 gas output also is hedged at an average Nymex price of about $5.80/Mcf.

Encana rebounded in the second quarter from earnings losses in the year-ago period and grew its unconventional natural gas and liquids production by 4%. Net profits in the quarter jumped to $176 million (21 cents/share), versus a year-ago net loss of $457 million (minus 62 cents) in 2Q2010. Cash flow was $1.1 billion ($1.47/share) while operating earnings jumped to $166 million (22 cents). Total production climbed to 3.46 Bcfe/d, which was 111 MMcfe/d higher than in the year-ago period.