North America's natural gas producers lately have been taking a licking but Encana Corp. is succeeding by continuing to optimize its portfolio and its operations, an executive said this week.

Eric Marsh, a senior vice president for Encana Corp.'s USA Division, spoke Tuesday at BMO Capital Markets Ninth Annual Unconventional Resource Conference. He told the audience that the Calgary-based producer long ago honed its "portfolio optimization" skills to navigate North America's combustible gas market. The latest "rebalancing" and "high grading" plan began in 2011 and takes the company through 2015.

"We manage our properties like any other portfolio, [it's] very diversified," Marsh said. "We look at our opportunities but at the end of the day the majority of capital is in the highest return projects."

In 2006 Encana's primary producing assets were U.S, Canadian and international properties, with a focus on shallow gas, the Jonah field in Wyoming, the Piceance Basin of Colorado and the Greater Sierra. Over the next four years the foreign properties were sold, key North American onshore assets were bought, and Encana spun off its oil-heavy properties through Cenovus Energy Inc.

By 2010 Encana had revamped its portfolio and was producing primarily from gassy properties that included the Haynesville/Bossier region, Cutbank Ridge, the Piceance/Denver-Julesburg basins, Jonah and coalbed methane.

The strategy now under way is taking a shift to liquids.

"As natural gas prices drop and liquids stay the same, those natural gas plays with more liquid content in them have the lower supply costs," said Marsh. "You can take the Deep Basin play [in Alberta] and that has supply costs in the $2/Mcf [area] or less, and it's very good to develop when prices are low.

"On the other side are dry gas without liquids, and that is a lot more challenged..." Generally, a gas project's full-cycle costs, from land acquisition to production, "really we're talking about a $4.50-5.00/Mcf gas price," said Marsh. "If anybody is producing dry gas, they are doing it for strategic reasons and not really from a full-cycle cost.

"When you get down to $3 gas prices that we're in today, we're challenged to put capital on a dry gas asset unless it's hedged, or you have other reasons to do it."

For instance, the Horn River Shale in British Columbia is a dry gas play. However, "it has some significant strategic value," he explained. Encana is a one-third partner with Apache Corp. and EOG Resources Inc. in one of the proposed liquefied natural gas (LNG) export facilities in Kitimat, BC.

"We do believe in an LNG solution on the west coast of Canada, and obviously we participate in Kitimat. We think there will be a material amount of LNG exports. And Horn River does play into that because it's close to the market."

The Haynesville Shale, another dry gas play, isn't on most producers' to-do lists. But Encana is finding a way to make the play work -- and work well.

"In 2011 we drilled a number of wells to prove up that resource," both the Haynesville and the Bossier interval, which runs above it, said Marsh. "We drilled about 10 long lateral wells between East Texas and North Louisiana. We just finished six long laterals in Louisiana and four in Texas."

Average wells in East Texas have "around 8,000-foot laterals," Marsh said. "The Haynesville typically is developed in a one section-square area. Typically there are six to eight wells per section, 4,600-feet average laterals...Now we are combining two sections, with 7,500-8,000-foot laterals together."

The combination proved successful. Encana had been spending about $9.5 million for a Haynesville well that produced around 8 Bcf. Now it's spending $13-14 million with average output of 14 Bcf.

"The strategic nature of this is important," said Marsh. "This means the majority of the program is going to be long laterals, with fewer wells and overall on a cost basis, better economics."

Encana is striving for a 9% return on capital and is driving to lower supply costs of about $2.75/Mcf. "And we're trying to accomplish this on a repeatable basis."

For example, a Haynesville section that was drilled using the longer laterals had a well that flow tested at 35 MMcf/d at 4,000 pounds/square inch.

"These are some of the strongest wells in North America. That's where we're going with gas assets. Drill longer laterals and we'll have very good economics. And we're able to compete in a $3.50 price environment."

By continuously working on improvements to its resource play hub design, Encana is targeting a $3.00/Mcf average supply cost target "or lower" on gas investments over the next three to give years.

Encana isn't wedded to all of its gassy properties. Last year it sold a bevy of midstream properties as well as its legacy Barnett Shale leasehold (see Shale Daily, Nov. 4, 2011; Oct. 24, 2011). And the company still will be gas-heavy in 2015, said Marsh. But expect to see more large-scale joint ventures. The Kitimat LNG project should begin exporting gas to Asian markets in 2014. The company's North American gas demand initiatives, which include pushing for more gas use in transportation, should be taking hold.

Liquids-heavy output should be on track from several of the emerging properties, too, including the Duvernay and Tuscaloosa Marine shales. In the Tuscaloosa play, in which the company has a 270,000-acre net leasehold, Encana has completed two wells and recently moved a third rig into the leasehold. Although few details were disclosed, "we are encouraged by the results," Marsh said.

Bigger investments over the next few years also are projected for Michigan's Collingwood Shale, the West Cutbank/Montney Shale and the Piceance Basin's Niobrara formation.

In 2011 Encana produced on average 3.4 Bcf/d of gas and 24,000 b/d of liquids. But the shift to more liquids production is under way.

"We'll be increasing our liquids extraction capacity with total liquids forecast to be more than 80,000 b/d" by 2015, Marsh said.

The portfolio changes are underpinned by "demonstrated methodology for developing resource plays from the ground up," he explained. Like many of its peers, Encana's initial exploration involves assembling a land base, then conducting pilot drilling to understand the technical aspect of the onshore play.

Commercial demonstrations then "crack the technical nut," which is followed by developing plays "manufacturing style," a technique honed by Encana first in the Haynesville Shale a few years ago.

"Encana has done a phenomenal job operationally," said Marsh. The company created "unique contracts" for some of its services, such as pressure pumping, which has allowed it to "never miss a date on supply. Rigs are committed on long-term contracts, often five- to seven-year contracts. We have specific steel arrangements that are long-term multi-year to mitigate the steel costs, which is a big piece of the equation."

Encana's supply costs rose 4-5% over the past year, while the industry was up "10, 11, 12%," Marsh noted.

"The natural gas industry is complicated; a lot of things are needed to move demand," said Marsh. "Industrial demand for gas is gaining strength but there are a lot of opportunities in power much as 10 Bcf/d. As you begin to look at the whole gas displacement with low gas prices, what you really see are power generators pushing a lot more gas today. It was 2.5-3.5 Bcf as of a few months ago, but when you get to a $3 price, it could be as high as 5 Bcf/d...on coal/gas switching...

"The power sector itself has announced there could be 30 gigawatts (GW) of coal shutdowns. We think that's the low end. It could be as high as 60 GW. When you add that up, and over three to five years for all of it beginning to happen, and it creates additional demand...In the longer term, it's very favorable for natural gas. The challenge is the next two to three years."