- Are efficiency increases too much of a good thing for the stimulation sector?
- E&P companies have been hit with reduced oil prices.
The oilfield services sector will learn soon enough if 2019 fulfills those holiday wishes for a happy new year. The sector—and well stimulation in particular— has just come through holiday-pause mode when a mid to high single digit demand reduction is seasonably expected. Wintertime weather could create choppiness before the market settles into annual cruise mode, just as it did in early 2018.
However, the ambience surrounding winter seasonality morphed into negative sentiment at yearend 2018 as oil prices fell 30% in roughly 60 days. True, there were interrelated factors including E&P budget exhaustion and a temporary oversupply in pressure pumping equipment, particularly in the Permian Basin and Marcellus.
Credit the stimulation sector, which exhibited efficiency improvement in mid-2018 from a greater percentage of pad drilling and zipper fracture stimulation. Stimulation crews added more stages per days and more hours pumping proppant and water downhole. In some cases, pump time improved 15% as stimulation crews captured efficiencies, first in hours and then later in minutes per stage.
Those efficiency gains allowed E&P companies to reach production targets sooner in 2018, and several reported annual budget exhaustion in the fourth quarter, creating white space on stimulation calendars for service providers.
Despite that, published data suggest the drilled but uncompleted well (DUC) backlog is rising and now lies shy of a six-month completion inventory. Although tight formation rig count flattened after Sept. 1, 2018, the industry still has 8,000 wells awaiting a completion crew, according to the U.S. Energy Information Administration.
The pause in demand impacted stimulation pricing, which fell about 15% on the spot market and threatened to reduce pricing from dedicated fleet arrangements as 2019 got underway.
Consequently, the oilfield services sector enters 2019 in a cloud of uncertainty as E&P companies grapple with attaining free cash flow neutrality in a dynamic commodity price environment.
E&P companies ended 2018 with a tailwind from reduced well cost. On the plus side, the transition to in-basin sand mines versus Northern white sand lowered well costs more than 20% in some cases. Furthermore, inflationary pressure from labor shortages abated as overcapacity in stimulation equipment and improved efficiency enabled the industry to do more with less.
The big story in 2018 involved the surge in regional sand use, which accelerated after mid-year 2018.
And that leads back to the main question for 2019. How long will the year-end pause in demand for stimulation services extend? Unfortunately, the industry has an imperfect record on forecasting. For example, expectations of a Permian slowdown in 2019 due to midstream takeaway capacity may not turn out as severe as anticipated.
The expectations that removing Iranian oil from the market via sanctions would keep global oil supplies tight and commodity prices high, gave way at year-end 2018 to fears that the global market will be oversupplied into 2020. This new fear, implying West Texas Intermediate oil prices between $50 and $60, especially in the face of 8,000 DUCs, comes as E&P companies were on the verge of attaining cash flow neutrality in an era where Wall Street no longer funds outspending for the sake of supply growth.
Questions remain as to whether industry observers are overstating demand for sand in the face of rising supply and for pressure pumping as the rate of growth for stage count, tighter spacing, proppant loading and lateral length tops out. Demand—and pricing—for oilfield services follows direction in commodity price.
Happy New Year? We’ll see.
The lawsuit alleges the U.S. Bureau of Land Management failed to adequately consider the adverse effects oil and gas drilling would have on the people and environment in eight Central California counties.
The deal would create the largest pure-play northern Midland Basin E&P with a 73,000-net-acre position and 12,000 boe/d of production that is expected to more than double through 2020.
Midcontinent E&P companies reduce well intensity to generate economic returns.