Sherlock Holmes and the curious incident of shale

Scotland Yard detective: Is there any other point to which you would wish to draw my attention?"

Sherlock Holmes: "To the curious incident of the dog in the night-time."

Scotland Yard detective: "The dog did nothing in the night-time."

Sherlock Holmes: "That was the curious incident.”

                                                   From the short story, Silver Blaze

What a difference a few years makes.

Back in June 2014, oil prices reached more than $108 a barrel and then crashed to less than half that 6 months later. And a year after that, notwithstanding the odd dead cat bounce here and there, the price had fallen to less than $30. For natural gas, the trajectory was similar; US price natural gas tipped more than $12 per thousand cubic feet (mcf) in 2008. It has been less than half that almost ever since, falling to around $2 in early 2016.

And that, said the skeptics, would be that for shale. The logic was compelling.

The once-in-a-generation innovation known as hydraulic fracturing (or “fracking”) had unleashed enormous reserves of hydrocarbon assets from shale in the United States. Between 2000 and 2010, US production of natural gas from shale had risen more than 10 times; by 2013, that had doubled again. Driven largely by shale, US crude oil production rose from 5 million barrels per day (b/d) in 2008 to 8.8 million b/d in 2014.

But all this was against a backdrop of high prices. When prices crashed, it looked like the shale boom would inevitably fizzle because its production costs were so high—an average of $80 a barrel in 2013, according to Rystad Energy. Moreover, shale plays decline faster than conventional ones—in a few years rather than decades—meaning there needs to be a constant supply of new wells to keep up production. “All signs are pointing to retreat,” argued Fortune magazine at the end of 2014. “Has the U.S. shale gale finally blown over?” asked Alberta Oil magazine 2 years later.  “The 21st century version of the American gold rush is coming to a swift end,” stated USA Today.

It all made perfect sense—and it didn’t happen. Why?

First, let’s acknowledge that the shale industry did not just sail blithely through these choppy waters.  Rig counts fell by almost two-thirds; lots of smaller players sank; and the industry is still struggling with debts incurred in the glory days.  Moreover, many companies have been much more successful at maintaining or increasing production than at delivering returns to shareholders.

But it is the dog that didn’t bark that resonates most loudly. Specifically, production stayed strong. In 2015—that is, after the oil price collapse—crude-oil production in the United States rose to 9.4 million b/d, the most since 1972, and most of that was from shale resources.  Output dipped slightly in 2016 (to 8.8 million b/d), but has come back strongly so far this year. Indeed, July 2017 saw a new record for shale production, even though prices haven’t reached $55 for more than 2 years. In April, the Energy Information Administration forecast US crude production would rise to 9.9 million b/d.

For natural gas, shale production rose in 2015, then dipped all of one percent in 2016. It, too, has come back strongly so far this year; like oil, natural gas from shale is on track to set a production record, even though prices are sticking at about half the peak in 2014.

Why didn’t the dog bark? Because the shale industry adapted to the altered situation not only with skill but with speed. In 2015 alone, the cost of completing a single shale well fell as much as 40 percent, according to the IHS energy consultancy. While the number of rigs fell after 2014—and are still nowhere near their peak—their productivity rose, due to the greater ability to drill horizontally; greater success in completing wells; and shorter average drilling times. In 2016, the average US shale well extracted 736,000 barrels of oil equivalent, according to Rystad; in 2012, it was half that. 

Also, the average rig is drilling three to four times as many wells per year as it did in the pre-price crash era. The cost of production in some areas is now around $30 a barrel, a lot more than the lowest-cost oil producers, but a lot less than high-end ones. No wonder investment in the sector is rising strongly. Since the second quarter of 2016, drilling activity has doubled, according to Energy Insights, a McKinsey market intelligence report.

These are the broad factors. There is also a specific one—the outrageous productivity of the Permian Basin in West Texas/Southeast New Mexico. The EIA estimates it will produce almost 3 million b/d by the end of 2018, or almost a third of total US production. Permian plays feature high productivity and low costs; since 2013, the break-even price has fallen from $98 per barrel to less than $40. Operators have also successfully hedged risks, giving them a healthy cash flow. According to Energy Insights, my colleagues estimated initial production in the Permian improved 15 percent to 30 percent per horizontal well from mid-2014 to mid-2016. For a time, the Permian was the only place in the US where onshore production was rising.

In the Bakken region of Montana/North Dakota, by contrast, production has not rebounded fully, and is not getting anywhere near the love that the Permian is, even though its costs are only slightly higher. In 2016, McKinsey estimated that deals in the Permian were five times as large as for the Eagle Ford (south Texas) and Bakken combined.  This reflects investors’ belief that the Permian, with its enormous undeveloped reserves, is where the future is. As my colleagues another Energy Insights report put it, “The thickness of the Permian’s stacked formations is believed to be 4 to 6 times the thickness found in the Eagle Ford or Bakken, indicating substantial reserve size. More importantly, the basin is quite young in its unconventional drilling activities.”

But to note the outsized importance of Permian now is not necessarily to assume that will always be the case. Indeed, the recent history of shale is a case study in why apparently obvious assumptions should be resisted. Assumptions tend to extrapolate from current conditions and knowledge—and the history of shale shows those can change drastically. As Sherlock Holmes put it, “There is nothing more deceptive than an obvious fact.” The next discontinuity, for example, could come from the use of big data to optimize mapping, output, and other operations.

Two more points. First, we cannot assume, either, that shale has a big future. Something could happen to displace it, either on the supply side (if assets run down fast or other, cheaper sources come up), or in terms of demand—if, for example, the global vehicle fleet begins to be powered by something other than fossil fuels.

More important, though, is the second point, which has to do with why shale muddled through. This was not because it was generally loved; it is, in fact, controversial. And it’s not because the US government came to its rescue. In the end, shale survived—and grew stronger—because it adapted to changing market conditions through innovation and operational improvements. Elementary.