ConocoPhillips during 3Q2010 curtailed about 180 MMcfe/d in North America, mostly in Western Canada, in response to continuing low natural gas prices, the producer said Wednesday.

About 150 MMcf/d was shuttered in the company’s Western Canadian operations and about a total of 35 MMcf/d was curtailed in the San Juan Basin and in the Bossier Shale, according to Clayton Reasor, vice president of corporate affairs. He and CEO Jim Mulva shared a microphone during a conference call with energy analysts.

“We would do more curtailments if we could,” Mulva said. “But we have partners…smaller independents, private producers…that won’t go along with curtailments. But we think [gas] has more value in the future.”

ConocoPhillips could produce more gas through the rest of this year and in 2011, Mulva said. “But that doesn’t make a lot of sense for dry gas…for a lot of places in North America. If we wanted production to be higher, we could do it, but why spend the money?”

Asked when or what the breakeven price would be for the Houston-based producer to bring the shut-in gas back on line, Mulva said the company could “get breakevens even today if we produced this [gas]. But we’re not willing to push volumes and essentially just break even.

“The market won’t sort it out in the short term, but it will become less dysfunctional, there will be more demand…Really, the way we look at it…prices today are…unsustainable. We have to see [gas prices] moving toward a $4, $5 range, and that we think with time will come. That’s what is factored into our decision.”

ConocoPhillips’ breakeven price for Western Canadian gas is $5.50-5.75/Mcf, while the breakeven in the Lower 48 states is $3.75, said Reasor.

Although some of its gas is shut in, the producer is accelerating plans in the liquids-rich Eagle Ford Shale, where capital spending in 2011 will more than triple from this year.

ConocoPhillips will spend about $300 million total through 2010 in the South Texas play, Reasor said. In 2011, the proposed capital spending budget for the Eagle Ford alone is set at $1-1.5 billion. All of the increased spending is to go for drilling and completion costs — no additional acreage is included in the numbers, he noted.

“These wells generally are producing around 1,500 boe/d [over a 30-day average rate], and well costs are running in the $8 million to $9 million range,” Reasor said. The ultimate reserve numbers are still being determined “but we are really encouraged by what we’ve seen so far.”

Mulva told analysts that ConocoPhillips’ oil portfolio in North America is “not well understood. But what we have in the Eagle Ford, in the Bakken, in the North Barnett and other areas that we have…We are more and more encouraged all the time and that’s why we’re increasing our spending by $1 billion [in the Eagle Ford] in 2011. We feel real good about that.”

In the Eagle Ford Shale the company has nine rigs currently active, with 15 wells successfully drilled and eight completed in the play in the latest quarter. The “pace of activity” is expected to increase through the rest of this year. ConocoPhillips also completed a second well in Poland to test a “possible” shale gas play. More tests on the first well are under way.

The producer remains on track to sell $10 billion or “somewhat more” of noncore assets in 2010 and 2011, but interest in the Rockies Express Pipeline (REX), which was put up for sale last year, is off the table, Mulva said.

“There hasn’t been a change in sentiment” concerning REX, but “we didn’t feel the bids we got were meeting our expectations,” Mulva said. “We’re not changing direction. We’ll come back at a later time…it could be late 2011 or 2012 when the markets are more interested.”

Net profits in 3Q2010 totaled $3.1 billion, which was more than double earnings of $1.5 billion in the year-ago period. Excluding gains from asset sales and one-time items, adjusted earnings were $2.2 billion ($1.50/share).

“We had a good quarter and operated as expected,” said Mulva. “Our plans to improve returns through disciplined capital spending, reducing debt and repurchasing shares are on track. Considerable free cash flow should enable us to execute our capital program to organically convert resources to reserves and annually increase dividends while repurchasing shares.”

Quarterly production from the Exploration and Production (E&P) segment was 1.72 million boe/d, down slightly from the year-ago output of 1.79 million boe/d. The decrease resulted from “normal field decline, primarily in North America and Europe, as well as asset dispositions. Increased production from China, Australia, Lower 48 shale plays and the Canadian steam-assisted gravity drainage projects partially offset the decrease.”

Output in the final three months of this year is expected to be flat at about 1.71 million boe/d. Full-year production is forecast to average around 1.8 million boe/d.

“Over the next several years, production declines are expected to be mitigated by new production from major projects offshore southeast Asia, LNG [liquefied natural gas] projects in Qatar and Australia, Canadian oilsands projects and Lower 48 shale developments,” said the CEO.

“During the quarter, the company’s Chemicals and Midstream segments experienced improved market conditions, compared with a year ago,” Mulva noted. “Our 50% interest in CPChem delivered particularly strong results, primarily due to improved ethylene margins, while DCP Midstream benefited from higher natural gas liquids prices.”

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