U.S. shale has dominated global oil production growth over the last few years. The industry survived a challenging period of contraction following the oil price collapse in 2014-2015, but a recovery in oil prices has been accompanied by some unexpected speed bumps in 2018. Pipeline bottlenecks in the Permian, higher production costs, a strain on services and other operational hiccups could act as a drag on further growth.
Shale E&Ps hope to continue to tweak drilling techniques and innovate their way out of some of these problems. Their success or failure will have global ramifications.
Profits remain elusive
This year was supposed to be the year in which the shale industry turned a corner. “Higher prices and operational improvements are putting the US shale sector on track to achieve positive free cash flow in 2018 for the first time ever,” the International Energy Agency (IEA) wrote in a recent report on energy investment.
However, many shale companies are running into some unexpected trouble. A Wall Street Journal survey of 50 U.S. oil companies found that they collectively spent $2 billion more than they generated in the second quarter. Roughly two-thirds of them were cash flow negative, even as oil prices rose sharply compared to a year earlier.
A Wall Street Journal survey of 50 U.S. oil companies found that they collectively spent $2 billion more than they generated in the second quarter.
Part of the problem is that the shale patch, and the Permian in particular, is suffering from a bout of cost inflation. The concentration of drilling in West Texas has pushed up costs across the supply chain, including for water, sand, labor, equipment and completion services, for instance. Cost inflation led to a raft of disappointing results in the second quarter. The companies surveyed by the Wall Street Journal either announced lower-than-expected production figures or revealed that they would have to spend more in order to produce the same amount of oil and gas.
Meanwhile, takeaway capacity in the Permian is mostly tapped out. The bottleneck has forced steep discounts for crude oil in Midland, Texas relative to WTI in Houston. The discount has exceeded $10 per barrel for the last few months, a differential that will likely persist until new pipeline space comes online late next year.
The problem puts the shale industry in a bind, forcing executives to decide between maintaining capital discipline, as many have promised, or increasing spending in order to grow production. “While selected operators increased yearly capital budgets by around 8% on average during 2Q, oil production volumes were revised upward by only 1.4%,” Rystad Energy said in a new report. “This disconnect might suggest that the shale industry requires more capital than before to achieve healthy production growth.”
Squeezed between steep discounts related to midstream bottlenecks on the one hand, and cost inflation on the other, Permian margins have dropped below that of other basins.
According to S&P Global Platts, in July the Bakken surpassed the Permian in terms of the most profitable shale basin in the country. This month, the Permian could fall below the Eagle Ford and the STACK in terms of rates of return per shale well. Squeezed between steep discounts related to midstream bottlenecks on the one hand, and cost inflation on the other, Permian margins have dropped below that of other basins.
“Many companies have promised to live within cash flow and grow by 10% or 20%, and it’s looking more and more like some are going to have to choose between the two,” Leigh Goehring, managing partner of Goehring & Rozencwajg, told the WSJ in an interview. “If the Permian growth engine slows, there aren’t many other easy sources of global supply.”
Pipelines are not the only problem. More recently, there appear to be some diminishing returns to economies of scale. In the past few years, shale drillers have extended laterals to greater distances, increased well density, and used more water and frac sand when drilling wells to coax out more oil and gas. These techniques have been deployed to cut drilling costs, lower breakeven prices, while also helping to boost production volumes.
But there are limits to these gains. For example, there is evidence that increasing well density—positioning more wells closer together—may have gone too far. In the Eagle Ford, the proportion of wells that were spaced less than 400 feet away from each other rose from 23 percent in 2012 to 58 percent in 2016, according to Rystad Energy. But that practice led to some problematic results, as wells in close proximity can sap pressure from one another and lead to lower levels of overall production. Since 2016, the Eagle Ford has seen the well density decline—the proportion of wells spaced less than 400 feet away from each declined from 58 percent in 2016 to 51 percent in 2018. In short, the industry hit the limit on well density and has pulled back. That dovetails with research from Statoil, which finds that wells should not be spaced any closer than 400 feet apart.
In addition, the industry’s use of proppants such as frac sand has scaled up dramatically. Pumping ever greater volumes of sand into shale wells has led to an explosion in production. In the second quarter, frac sand demand in North America rose nearly 30 percent year-on-year to 162 billion pounds, according to a new report from IHS Markit. “Sand proppant demand is at record highs—the growth rate is extreme by any measure,” Brandon Savisky, senior market research analyst at IHS Markit, said in a statement.
Whiting Petroleum has apparently halved the volume of sand it has used in some of its wells in the Bakken.
However, Whiting Petroleum, a driller with operations in North Dakota and Colorado, says that it has reduced the amount of proppant used when drilling wells to keep costs down. “New diversion techniques are allowing us to complete better performing wells while using about 30% less proppant, reducing capex by approximately $400,000 per well,” Whiting Petroleum CEO Brad Holly told an industry conference on August 20, according to S&P Global Platts. “We optimize completions for each well. Going bigger is not always better. It is about optimizing completions.” Whiting has apparently halved the volume of sand it has used in some of its wells in the Bakken. To be sure, the reduction in proppant by Whiting is likely an exception to the industry trend, but like well density, it suggests there are limits to the “bigger is better” model.
Production still set to rise
The EIA still sees significant production growth in the U.S. this year and next. Total oil production is set to rise by roughly 1.4 million barrels per day (Mbd) this year, hitting an all-time annual high of 10.7 Mbd. The EIA forecasts a slowdown in growth to just 1.0 Mbd in 2019, with total output rising to 11.7 Mbd, but the increase is still substantial given the headwinds facing the industry, including pipeline bottlenecks, price discounts and cost inflation.
The recent uptick in costs and productivity issues could also be a reflection of planned spending increases that will translate into higher production next year.
The problems might not be as bad as they appear. The recent uptick in costs and productivity issues could also be a reflection of planned spending increases that will translate into higher production next year. “In fact, while a part of increased spending is due to service cost inflation, a significant part of the incremental budget is also planned to be used for additional drilling throughout 2H 2018 to support more intensive completion activity and production growth in 2019,” Rystad Energy wrote in its report. For example, Pioneer Natural Resources hiked its spending plan by $400 million. While some of the increase is the result of cost inflation, the larger outlays will also fund four additional rigs in the Permian and an increased rate of well completions, which should deliver higher volumes in 2019.
Increased spending levels this year need not suggest the industry is in trouble. The pipeline bottlenecks in the Permian are forcing companies to drill wells but put off completion until pipeline projects come online. When the region sees more takeaway capacity, there will likely be a rush of completions, along with a narrowing of the discount. In other words, the shale industry has hit a rough patch, but it isn’t clear that the problems are permanent.