Schlumberger Ltd. and Halliburton Co. offered a sober reminder during their third quarter conference calls that producers working in the Lower 48 have reduced their activity and their spending, with neither likely to recovery by year’s end.

Paris-based Schlumberger, with major operations headquartered in Houston, reported net losses of $11.97 billion (minus $8.22/share), versus year-ago profits of $659 million (47 cents). Excluding a one-time impairment of $12.7 billion, adjusted earnings were 43 cents/share in 3Q2019. Revenue edged up slightly year/year to $8.54 million from $8.50 billion, with an 11% decline in North American revenue offset by 8% growth in international operations.

Schlumberger took a $1.6 billion charge in the latest quarter for its North American hydraulic fracturing business.

“This quarter’s results reflected a macro environment of slowing production growth rate in North America land as operators maintained capital discipline, reducing drilling and fracture activity,” CEO Olivier Le Peuch said during his first conference call at the helm. “Our year-to-date high single-digit international revenue growth continues to be underpinned by international investment levels.

“Market uncertainty, however, is weighing on future oil demand outlook in a climate where trade concerns are seen as challenging global economic growth.”

Schlumberger, a bellwether for the industry, was the first of the oilfield services (OFS) operators to issue third quarter results. North American revenue overall increased 3% sequentially, excluding the Cameron unit, as strong offshore sales outpaced minimal onshore growth by exploration and production (E&P) customers. A modest increase in the pressure pumping business, OneStim, was offset by softer pricing. International revenue of $5.6 billion increased 3% from 2Q2019.

“Sustained international activity drove overall growth despite mixed results in North America,” Le Peuch said. Former CEO Paal Kibsgaard, who retired in August, had warned during the 2Q2019 conference call that North American land activity through the end of the year would be down.

“As we exited the quarter, OneStim activity decelerated as fracture programs were either deferred or canceled due to customer budget and cash flow constraints,” Le Peuch said.

Revamped Strategy

Schlumberger last month unveiled a strategy to move the company forward with four key elements: digital transformation, fit-for-basin solutions, capturing value for customers and fostering capital stewardship. Capital stewardship, said Le Peuch, relates to more stringent capital expenditure allocation by E&Ps and a review of the portfolio, “particularly in North America, through the lens of fit-for-basin attributes, customer performance and return on investment.

“We are already off to a good start on digital,” he said. The company is committed to an “open digital environment that unlocks customer performance” for exploration and production customers.

Schlumberger recently commercialized a digital formation testing platform and fit-for-basin technologies including the Ora intelligent wireline formation testing platform, said to be the first tool built by the company on a cloud-native platform. It combines software and hardware to deliver dynamic reservoir characterization in all conditions.

“In Mexico, the Ora platform was the first-ever wireline formation tester able to collect high-quality gas condensate samples in a challenging carbonate formation,” the company noted. Ora helped state-owned producer Petroleos Mexicanos triple estimated reserves in one of its land discoveries.

Another technology, the NeoSteer at-bit steerable system, was used by SRC Energy Inc. in the Denver-Julesburg Basin of Colorado to drill a 12-well pad targeting vertical, curved and lateral sections. The rate of penetration (ROP) increased by 20%, saving “as much as 21 hours in a single well while targeting various zones...”

Another fit-for-basin technology, the Aegis armor cladding alloy for drillbits, was used in the Anadarko Basin of Oklahoma in eight wells for an undisclosed operator, resulting in an ROP increase of 36%. The customer reduced drilling time by 27%, or about 179 hours across the eight runs.

This year the number of jobs overall using fit-for-basin technologies “has increased six-fold compared with 2018,” management noted.

In North Dakota, for example, OneStim used the company’s BroadBand unconventional reservoir completion services for Whiting Petroleum Corp. to increase oil production in two infill wells, outperforming nearby offset wells by 37% in the Bakken Shale and 48% in the Three Forks formation, while using similar proppant intensities.

OneStim also deployed WellWatcher Stim and Broadband in the Permian Basin for Callon Petroleum Co. to avoid parent-child well interference. Also in the Permian, Occidental Petroleum Corp. worked with Schlumberger to establish a differentiated unconventional asset development program.

Occidental built the Aventine facility, an integrated operations and logistics center in New Mexico, and Schlumberger built and operates a base within the facility.

“Both companies are achieving record hydraulic fracturing efficiencies through collaborative optimization of workflows and new fit-for-basin technologies,” Schlumberger noted.

OneStim fleets have broken Permian records for each company for stages/month four different times this year, with one fleet achieving 267 stages. In addition, one fracture fleet completed a two-well pad with an average 20.2 hours of pumping time per day, and a single-day maximum of 21.8 hours, above typical industry pumping times of 12-15 hours/day on comparable operations.

 The No. 2 OFS operator, Houston-based Halliburton, issued its results Monday. Following a slow third quarter, CEO Jeff Miller told analysts the domestic fracturing business is forecast to decline further in the final three months, with margins down by 125-175 basis points and revenue plummeting by low double digits.

“Feedback from our customers lead us to believe that the rig count and completions activity may be lower than the fourth quarter of last year,” Miller said.

North American revenue accounts for more than half of Halliburton’s global total, and it was off 21% year/year and 11% sequentially. Completion and production activity in North America slumped by 16% from a year ago, and more land equipment was idled.

Net earnings in the quarter declined to $295 million (34 cents/share), off 32% from year-ago profits of $435 million (50 cents) and down by 11% sequentially. Revenue was off 10% to $5.55 billion.

Supply and demand “uncertainties” weighed in the third quarter, in part from the “ongoing U.S.-China trade tensions and negative economic data out of Asia and Europe,” Miller said. While international growth overall is continuing at a steady pace, the outlook is not solid in North America, where “customer spending has decreased and was largely concentrated in the first half of the year.”

The Lower 48 rig count declined by 11% from the second to the third quarter “for the first time in 10 years. And while historically the third quarter used to be the busiest in terms of hydraulic fracturing activity in the U.S., stage counts declined every month this quarter.”

As a result, the market for drilling/completion services in North America “softened during the third quarter, impacting service company activity; Halliburton was no exception.”

Pricing pressures are eroding margins as U.S. exploration and production customers work to lower overall costs to meet their cash flow objectives.

Stacking it Up

“We are stacking equipment,” Miller said. “In the third quarter, we stacked more equipment than we did in the first six months of the year. While this impacts our revenues, we would rather err on the side of stacking and work for insufficient margins and wear out our equipment.”

At the same time, the OFS giant is reducing costs. During the recent downturn, Halliburton reduced costs by $1 billion in 2016, Miller noted. It is doing the same today by reorganizing, reducing staff and lowering fixed costs in North America.

Halliburton also is “aligning with the right customers...that are spending and that value our services” by integrating well completions with wireline and fracturing services. “It is one thing to have both product lines and another thing to integrate them technically and culturally and achieve lower cost on location,” Miller said.

Halliburton also is upgrading technologies to improve efficiencies and reduce personnel on location. “This technology integration, which is hard to duplicate, improved customer efficiency, but more importantly, it improves our margins,” which he said is the “right approach” for the North American market.

For the final three months, Halliburton expects more of the same.

“We expect customer activity to decline across all basins in North America land, impacting both our drilling and completion businesses,” Miller said.

‘Oversupplied’ Natural Gas Market

The end-of-year holidays and potential weather impacts “are the usual culprits,” but U.S. E&Ps are committed to cash flow generation. An “oversupplied” natural gas market and “concerns about oil demand” also lead to potential “softness in 2020.”

E&P “budget exhaustion” already has begun, Miller said. Through the end of the year, Halliburton is planning more cost reductions. Estimates are still being finalized, but it expects to capture around $300 million in annualized cost savings over the next few quarters.

The “narrative for North America” is changing. While the cadence of activity may remain the same over the near term, Miller said there are some trends Halliburton is scrutinizing in the U.S. land market. The No. 1 item is equipment attrition.

“Given demand deceleration, the service industry has adjusted accordingly and cut capital spend this year,” he said. “There were hardly any new equipment additions, and maintenance spending has been severely curtailed.”

At the same time, service intensity in the fields has not slowed as multi-well pad drilling has continued, with lateral lengths extended and proppant loading increased.

“The direct result of higher service intensity, especially in terms of hours pumped per day, is the increase in maintenance frequency. This should accelerate the long-awaited equipment attrition from the market, both voluntary through stacking and involuntary.”

There is less horsepower available in the market, and service operators have begun cannibalizing stacked equipment for parts rather than paying for replacement components because of budget constraints.

“We expect attrition to continue into 2020,” Miller said.

U.S. E&P customers also have changed their buying behavior and now are contracting for services and integrated packages to gain cost savings. Miller said this is how the North Sea market evolved.

Halliburton now is working on integrated projects in the Permian Basin and the Bakken Shale. One other trend the company is watching is the deceleration of incremental U.S. production growth brought about by E&P capital expenditure (capex) discipline.

“The record breaking 2018 growth will not be replicated in 2019,” Miller said. “In fact, current projections for 2020 indicate a further decline in production from the current year estimates to maximize production for every capex dollar they spend. Operators will require technologies that can improve both efficiencies and well productivity.

“Instead of counting stages, they want to make every stage count. For this, I believe they will turn to Halliburton.”