The oilfield services (OFS) sector, slowly returning to normal following the downturn four years ago, now faces more uncertainty, as oil prices continue to decline and Lower 48 producers trim spending plans for 2019.
The OFS sector’s customers, exploration and production (E&P) companies, began finessing their capital expenditure (capex) plans during the third quarter, just as oil prices began to slide.
West Texas Intermediate (WTI) had moved to above $75/bbl in early October, but a month later, prices had fallen below $60. On Thursday, New York Mercantile Exchange WTI futures slid $1.61 to settle at $44.61/bbl. In the lead-up to the Christmas holiday, futures fell below $46/bbl for the first time since August 2017.
The slide already is causing anxiety, with four onshore E&Ps planning to retreat in 2019 with lower capex and activity.
Permian Basin pure-plays Diamondback Energy Inc., Parsley Energy Inc. and Ring Energy Inc. are dropping rigs and fracture crews. Goodrich Petroleum Corp. also plans to reduce capex in its operations, which are spread across the Haynesville, Eagle Ford and Tuscaloosa Marine shales.
More are likely to follow, analysts said. While many E&Ps won’t announce spending plans before January, it’s going to be later than usual because of the “unprecedented decline in commodity prices and ongoing infrastructure constraints,” Evercore ISI’s James West said.
Upstream budgets overall should increase, weighted to the second half of the year, but the risk of spending cuts is more pronounced than in recent years, he said.
Another top-of-mind concern is the “considerable capital discipline espoused by E&Ps and international oil companies alike,” West said. Still, the Evercore team is positive that upstream investments “have to return in order to alleviate an inevitable global supply crunch that cannot be addressed by U.S. shale production growth alone.”
Analysts J. Marshall Adkins and Praveen Narra of Raymond James & Co. said the OFS outlook is not as bright as it was only a few weeks ago.
“November's drop in prices came squarely during E&P budget season, giving operators second thoughts about their 2019 capex plans, which consensus expected to be higher than in 2018,” the Raymond James team said. “We see oil prices remaining challenged through the first several months of the year, and thus our forecast of E&P cash flow and capital spend have lowered.”
Domestic E&P cash flow is forecast to decline by 7% year/year if WTI averages $53/bbl. At that price, E&Ps could cut their initial capex plans by up to 10%.
The U.S. rig count also may fall from peak-to-trough by 7-10% in the first half of 2019, with completions outperforming drilling, Adkins and Narra said.
Budget Squeeze Until Summer?
With E&Ps pinched, OFS pricing is likely to be squeezed through June.
“While estimates varied as to the timing of the recovery, it is now clear that a quick return to work in January of 2019 will not materialize,” said the Raymond James team. “That said, our forecasted recovery in oil prices for the second half of 2019 sets up the likelihood of a sharp ramp in activity at the end of the year, followed by a strong 2020…”
Analysts with Tudor, Pickering, Holt & Co. (TPH) recently quizzed 100 energy investors about what they see for 2019 price-wise.
“On the macro level, respondents were split on a $50-55/bbl and $55-60/bbl WTI 2019, with a $10/bbl Brent-WTI spread. To that end, 80% of respondents desired operators to budget in the $50-55/bbl WTI range.”
About 70% said they preferred no outspend or wanted positive free cash flow in any commodity case.
“In terms of growth, the majority of respondents indicated that a 5-10% rate of growth is preferred over the short and long term, and on returns, 76% indicated that shareholder return initiatives are a must in the near future.”
Meetings with clients outside of Houston confirmed those views, said the TPH team. Spending within cash flow “is paramount to capital allocation” next year.
The U.S. rig count has continued to grind higher during the final three months of the year, but the activity has masked volatility across the OFS sector, according to Evercore’s West.
The energy industry used to have three to four years of positive activity followed by a slowdown over a couple of quarters. Today, it “has been more like three to four quarters of growth before a slowdown occurs,” he said.
That gives the OFS sector much less visibility because onshore E&Ps in particular can cut back much more quickly when they need to.
“These shorter cycles are forcing the industry to become more prepared for these trends around unconventional development, and companies are trying to build a more sustainable business model around it,” West said.
Disconnect In Crude Prices, OSX
To illustrate the financial dilemma the OFS sector faces, West said if an investor put $1 in the PHLX Oilfield Services Sector (OSX) 20 years ago, “it would be worth $2.10 today, which is less than $2.30 for the S&P, $4.75/bbl of WTI, and $6.35/bbl of Brent.
Year-to-date the OSX is down roughly 34%, while Brent is up 10% and WTI has gained 14%.
“We believe the disconnect between crude and the OSX is emblematic of the economic rent paid by OFS, while their upstream counterparts exacted pricing concessions despite significant technological strides made by service firms to yield increased productivity,” West said.
For example, a typical long-lateral Permian well today takes about 20 days to complete, where it used to take close to 80.
The OFS sector has to “reclaim its position in the value chain” and boost pricing, he said. “We stand by this view and patiently wait for the group to coalesce around this idea.”
Squeezing out more pricing gains may be a challenge, particularly for sand, which is used as proppant in fracturing/completions.
According to Rystad Energy, the 2019 outlook for U.S. proppant “is mixed if not outright depressed. Room for price improvements is hard to spot.” Fracture sand demand is forecast to remain flat at current oil price levels, but supply is forecast to increase by 28%.
“The recent oil price collapse has generated a lot of uncertainty on the demand side of the equation next year,” said Rystad’s Ryan Carbrey, senior vice president.
Rystad estimated a range of 109-133 million tons of sand in varying WTI oil price assumptions of $50-73/bbl.
“This represents a very dramatic difference, as the low end of this range implies virtually no demand growth in the proppant market relative to what we saw this year, at a time when a lot of new supply is set to come online,” Carbrey said. “It is hard to see any room for pricing improvement in such an environment.”
More E&Ps are opting for in-basin sand, aka last-mile operations, to keep prices low.
“With the penetration of in-basin sand and the stabilization of proppant demand in the second half of 2018, we have already seen material downward pressure on northern white minegate prices,” Carbrey said. “In fact, the adoption of in-basin sand in the Permian has evolved at a faster rate than we initially expected.”
A long list of in-basin mines are underway in the Permian and other basins not yet operational could boost total U.S. sand supply to 250 million tons by the end of 2019, a 25% increase year/year, according to Rystad.
The potential oversupply -- or lack of drilling -- has begun impacting some operations.
Houston-based Solaris Oilfield Infrastructure Inc. said it has amended a contract with its primary customer at the recently completed transloading facility in Kingfisher, OK. The amended contract reduces the minimum contracted annual revenue to $3.6 million beginning in March and shortens the initial term to Dec. 31, 2020. The amended contract also triggered a partial termination payment to Solaris of $26 million and allows a portion of the previously dedicated storage and rail track to be used by other third parties.
Solaris CEO Bill Zartler said the company was working to accommodate “the shifting needs of both our customer and the industry. While the industry shift to in-basin sand has lowered potential demand for many transload facilities, including Kingfisher, it has the opposite effect on our mobile proppant systems. In-basin sand logistics removes a storage buffer from the supply chain and relies heavily on trucking, which introduces increased volatility to the total supply chain.”