Schlumberger Ltd. and Halliburton Co. executives last week expressed concerns about North America's pressure pumping services market -- and not just in natural gas basins. The move by North American land rigs and service capacity from natural gas fields to liquids-rich targets has accelerated, but the pricing weakness first experienced in the gas fields has begun to shift to the liquids plays, said Schlumberger's CEO.
In addition, some of Halliburton's 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, said CFO Mark McCollum.
Despite a strong quarterly report, Schlumberger's executive team warned in a conference call on Friday that profit margins for the land business in North America -- one of its growth drivers -- are beginning to fall. Crushingly low gas prices have forced producers to flee gas drilling for more profitable oil and liquids-rich basins, which in turn have created logistics obstacles for oilfield services companies -- a fact also alluded to by Halliburton last week.
Pressure pumping service prices, which are a key component of hydraulic fracturing (fracking) prices in unconventional drilling, continue to weaken because of the transition, said Schlumberger CEO Paal Kibsgaard. Even though the oilfields require more services than gas fields (such as more frack stages), oil pumping requires less pressure and less horsepower. In the first three months of the year North American margins declined 409 basis points to 22.8%.
The dynamic in the switch from gas to oil work is "going to contribute to an oversupply of horsepower," Kibsgaard told analysts. The reduction in pressure pumping prices in the second quarter "is a given." U.S. oil growth drove to "record levels," but "natural gas is at a 10-year low, and it's unlikely to recover in the near term." Schlumberger remains "uncertain" about the outlook for dry gas in North America. "We still expect to see U.S. land activity at 2011 levels, provided the gas [activity] is offset with liquids-rich basins."
Pressure pumping, which is Halliburton's forte, has existing contracts that are still 80-85% long term, and 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 not exposed to that much," said Tim Probert, president of strategy and corporate development.
Contracts vary by basin, noted 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 Halliburton 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, Halliburton today primarily operates a 24-hour, seven-day-a-week operation (24/7), "being more one akin to a manufacturing operation," said Lesar. "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."
The total number of rigs operating in the United States, which been on the increase since 2Q2009, decreased to just under 2,000 in 1Q2012, according to Baker Hughes and NGI's Shale Daily calculations. Annual U.S. average marketed natural gas production per operated rig, which had slowly declined for several years beginning in 2002, has increased again in the past few years, jumping to 27.3 Bcf/rig in 2009 from just 14.2 Bcf/rig in 2008, and remained strong at 27.2 Bcf/rig last year.
Halliburton's net profits rose by 22.7% in 1Q2012 to $627 million (68 cents/share), versus $511 million (56 cents) in the year-ago period. Revenue jumped 30% year/year to $6.87 billion. Excluding a $300 million charge related to estimated losses related to the Macondo well blowout in 2010, in which Halliburton was the well cementing contractor, the company earned 88 cents/share in the quarter. Wall Street had expected the company to earn 85 cents/share on revenue of $6.79 billion.
Schlumberger's business relies on more than land, and North American margins should be offset by higher margins in the Gulf of Mexico, which has returned to pre-moratorium drilling levels, said Kibsgaard. Halliburton also reported optimism about deepwater oilfield services work. The Paris-based firm posted profits of $1.3 billion (97 cents/share) in 1Q2012, versus $944 million (69 cents) a year ago. Excluding one-time items, net earnings rose to 98 cents from 71 cents, on revenue of $10.61 billion.
Tudor, Pickering, Holt & Co.'s John Lawrence and Jeff Tillery said in a note Friday Schlumberger's report overall offered no surprises, but the news about North America's pressure pumping activity "is a question mark," because it isn't just dry gas where pressure pump pricing is falling, "it is happening in oil/liquids basins as well."
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