Some of Halliburton Co.’s pressure pumping deliveries in North America originally planned for this year will be deferred to 2013 to deal with “inefficiencies” that followed onshore producers moving from dry natural gas plays to more liquids-rich regions, company executives said Wednesday.

CFO Mark A. McCollum told financial analysts during an earnings conference call that capital expenditures for this year still will range from $3.5 billion to $4 billion. However, more capital now will be allocated to international projects recently secured or some the company expects to win over the next few months.

In addition, Halliburton is investing in new technologies for the drill site and offsite monitoring — and reducing work crews at less popular gas drilling locations.

“Part of that will be achieved through the rollout of these new pumps and the blending units and other things that allow us to do less maintenance out on location,” McCollum said. “The other thing will also be the mobility plan that helps us in achieving more of our remote operations initiative, which again will be later in 2013.

“But in particular areas such as the gas basins, our guys are very focused on cleaning out those crews as we speak, as the work provides for it. Other places [like the liquids and oil basins], we’re still scrambling as you might imagine, and it’s all hands on deck.”

Halliburton detects “a lot of movement out there,” said McCollum. “It’s a very dynamic market, and so we’ll continue to try to adjust as we see…It’s difficult at this juncture, given the dramatic decrease in the gas rig count and the current outlook for gas, to say that we would normalize at that point there…I’m not going to try to ‘crystal ball’ where we see things going in 2013.

“But I do think structurally, in our business, when you look long term, through the cycles themselves, that mid-20s range is essentially where our business tends to operate. And we are driving initiatives inside the company to reduce our cost structure in a way that can give us a fighting chance even if the market begins to flatten out toward the end of the year that we can find our way back to those mid-20s [% margin] range if we execute well against our cost initiatives.”

In regard to pressure pumping, which is Halliburton’s forte, Tim Probert, president of strategy and corporate development, said the company’s existing contracts are still 80-85% long term, and its exposure to the spot market is “quite limited…Clearly, there is…a more aggressive stance in those spot markets, but it’s one [that] frankly we’re just not exposed to that much.”

The pressure pumping contracts vary by basin, said McCollum. “We have customers in certain of the liquids basins that are only re-signing up for term contracts; they’re extending the contracts that they have and they’re still continuing to be at fairly good prices.” In some of the oil basins, the extended contracts are not lower, he added.

The Eagle Ford Shale is “a much more vulnerable basin” because of its proximity to the gassy Haynesville Shale, said Probert.

Halliburton is selling “efficiency; we’re selling lowest unit cost because of the efficiency,” said CEO Dave Lesar. “And I think we are having a different kind of conversation with those customers than maybe some of our competitors would have to have.”

In forsaken gas basins like the Haynesville Shale, he was asked if Halliburton had a long-term contract customer asking for price relief, would the company grant it?

“You know what? There’s hardly anybody left in the Haynesville but Halliburton. So you can read into that comment what you will.” In other regions, “are we rolling pricing back on existing contracts? The answer is ‘no’ [on] the contracts that have term left on them. Those that are coming up for tender, we are having discussions about where the market pricing for long-term types of contracts are. We are not going to spot market by any stretch of the imagination.”

Beyond the current operational issues, as crews transition from gassy basins, Lesar said Halliburton today primarily operates a 24-hour, seven-day-a-week operation (24/7), “being more one akin to a manufacturing operation. And absent the dislocation of crews, which obviously have an impact on up-time and downtime, we don’t move a crew unless we know where it’s going, we know what customer it’s working for and we know the price that it’s going to work at.

“So we don’t incur a cost to basically pick them up and move them somewhere without knowing what the financial impact is going to be. I would say that’s not true with a lot of our competition who are being chased out of some of these basins, like the Haynesville, and those crews are going basically looking around for work.”

Lesar said, “That’s why the transactional market pricing is so disruptive today. But…that’s not a market that we generally play in. So when we say we’re moving a fleet, it’s not going looking for work. It knows where it’s going, knows who it’s working for and knows the price that it’s going to work at.”

The Permian Basin, which has become “new” after producers realized its huge liquids potential, also has begun to move to 24/7 operations, noted the CEO.

“It’s just starting to go there…Typically the Permian Basin has not been a market where the operators saw the need to have 24-hour operations. But we have actually gone to 24-hour operations with some of the bigger players out there and have demonstrated to them the efficiency of it. Now that’s caused some disruption within the operators because they’ve had to change their work practices, their completion practices. But as it’s gotten more competitive out there, they’ve seen the benefits of it. But even in a market that’s traditionally not 24 hours, it’s starting to basically embrace it.”

“North America revenue grew 1%, while operating income declined 5% compared with the previous quarter,” McCollum said. “Inefficiencies associated with equipment relocations, continuing cost inflation and pricing pressures in certain basins impacted our margins during the first quarter. We expect disruptions related to rig movements to impact us in the near term.

“And perhaps with the exception of guar, we anticipate some relief from suppliers in the second half of the year related to high cost of proppants and other materials.” Guar is a component used to thicken a material used in hydraulic fracturing operations.

Because of the U.S. onshore “challenges and the negative impact of the seasonal Canadian spring breakup, we expect to see lower revenues and margins dropping by 200-250 basis points in the second quarter. We also now anticipate margins could drift toward the low-20% range by the end of 2012. The market is understandably very dynamic right now. These margin expectations depend on, among other things, our success in recovering inflationary cost increases from our customers and how soon the natural gas rig count levels off. We should have a better feel for this after the second quarter.”