Almost half of the drilling in the U.S. onshore now is being done on multi-well pads, further moving attention from the rig and well count and more to horizontal footage drilled and the number of fractured stages per well, Halliburton Co. CEO Dave Lesar said Monday.

Lesar and his executive team shared a microphone during a conference call to discuss second quarter performance and to highlight the near-term forecasts.

The largest pressure pumping provider in North America has stumbled in recent quarters — as have other service providers — with operators moving to liquids prospects from natural gas. Dragged down by a slow Canadian spring break-up and flooding in Alberta, North American revenues declined 8.2% from a year ago, while international revenue jumped 18%.

The 2Q2013 profits fell 7.9% year/year (y/y), on net income of $679 million (73 cents/share) from $737 million (79 cents). Revenue in the latest quarter rose slightly (1.1%) to $7.3 billion. Wall Street had pegged earnings at about 72 cents/share on revenue of $7.25 billion.

International business is growing, but North America remains a top priority. It could use more natural gas drilling to help Halliburton’s growth in the near-term, Lesar told analysts. More efficient drilling is helping the cause, he said.

More U.S. wells are drilled on multi-well pads, reducing costs and the amount of equipment required. The changes in how wells are drilled and how gas and and oil are extracted through hydraulic fracturing require a new mind-set.

“As we have tried to allude to over the last couple of quarters, I think the people that are analyzing our industry have got to move away from rig count,” said Lesar. “They’ve got to move away from well count and really look at sort of horizontal footage drilled…Given the position that we have in the U.S., and given what we see out there, we think that basically the pad drilling is 50% or so. The other thing that you see is pad sizes are getting much larger and that just drives more efficiency and more service intensity.”

In discussions Halliburton is having with clients, “better wells are still very important…That plays to our strength in terms of designing, custom chemistry for the best production, the subsurface insight that allows us to design the best producing wells. So those continue.

“But as we have said, we continue to see some pricing pressure, certainly variable, across different basins. I guess the pricing pressure doesn’t go away as long as there is the overhang out there of excess equipment. But I think our technical ability to sell into those contracts is still very good.”

CFO Mark McCollum acknowledged that wells and footage numbers are murky and possibly not accurate in some cases. However, Halliburton’s rig efficiency remains “at a leading edge…Anecdotally when we talk to operators, they describe what’s been done. Until now, it’s been drilling hold and arguably better exploration [and] even some really big operators have said that they were waiting to really go for a long development…We’ve seen upper single-digit-type improvement in terms of efficiency even in the current year that’s on the back of double-digit efficiency gain last year. I expect there is still headroom to grow around that scenario.”

Halliburton is the only pressure pumper at 100% utilization, said McCollum, but the North American market continues to have a 20% surplus in stimulation equipment. The company earlier this year said it expected the rig count to increase gradually, eliminating the overhang by late this year or early in 2014 (see Shale Daily, April 23). That timeline, said McCollum, “is beginning to push out just a little bit…on the back of what we’ve seen in terms of the overhang that’s still there, though the thesis we stay with in terms of the longer things go, cannibalization starts to occur of equipment in the market. So I still believe there is the ability to consume the overhang…over time, but I don’t see that as necessarily a 1Q2014 event.”

As efficiency levels edge higher, the rig count moves lower, said Lesar. “I think the combination of both sort of says it probably [will be] a little longer overhang in this pressure pumping market…We have always said that we see no reason that in a reasonably robust gas market that we should not be able to achieve normalized margins. And for us, normalized margins would be in the mid-20s…Obviously we’re going to need help in gas from the gas market.”

There are some positive signs moving forward. The North American completion/production segment’s revenue increased sequentially nearly 5% from 1Q2013, showing a progression in pressure pumping strengthening. “Consistent with the first quarter, approximately 85% of our crews are on the long-term contracts and about three-quarters are working 24-hour operations,” said COO Jeff Miller.

“Additionally, in some cases, we’re seeing operators increasing the number of stages on horizontal wells, performing as many as 40 stages per lateral in the Marcellus Shale…It’s our view that the result in increased well count and stage count could absorb the remaining 4% of the excess horsepower and help drive service intensity across all product lines” but “we anticipate the pricing pressure will persist to some degree across many North American basins in 2013.”

The Houston operator is executing around “surface efficiencies, subsurface technology and testing chemistry,” said Miller, offering “differentiated services” for U.S. and Canadian customers. As part of the strategy, the Frac of the Future and Battle Red initiatives “are really the platforms that enable surface sufficiency. We expect to see increased performance at the wellhead, as we incorporate these tools into our processes.”

Battle Red, whose full rollout across North America is set for completion in early 2014, applies new processes and technologies that improve efficiencies.

“We’re targeting a 50% reduction in days to bill our customers, and we expect these tools to also be able to help manage inventory level, reduce overtime and optimize low freight deliveries. As an example, we’ve already seen a 15-20% reduction in costs around trade and standby charges.”

Frac of the Future, which has been ongoing since 2011, is designed to reduce capital and operational expenditures on the well side. The initiative is reducing fleet maintenance costs by 5-30%, Miller said. Efficiencies gained “also allow us to reduce the equipment needed on location by an average of 25%.” In the past few years, Halliburton has reduced crew charges by close to 30%. “When we look at what we’re able to deliver on a stage per headcount basis, we’ve seen a 40% rise in executional efficiency over the same time period.”

By the end of 2013 Halliburton expects close to 20% of its fleet will be converted to Frac of the Future equipment. “The rate at which we deploy going forward,” said Miller, “will be dependent on three factors: North American natural gas activity, the growth of international oil conventional and our retrofit to replace older equipment.”