As global oil prices fell from more than $100 a barrel in July of 2014 to less than $30 a barrel in January of 2016, industry observers expected to see a precipitous drop in U.S. shale oil production. At the time, these forecasts seemed sensible. Shale wells were definitely not the cheapest source of new crude oil production. In fact, the break-even costs for North American shale producers were thought to be about three times higher than for similar costs for Middle Eastern producers. Shale wells also deplete faster than conventional wells, with production rates falling about 70% after the first year. On top of this, many shale producers used inflexible debt financing to fund their operations, making a drop in operating cash flow potentially catastrophic for ongoing development efforts.
To the surprise of many, shale production actually increased during that drop in prices. Total production peaked in March of 2015, and has only fallen by 17% since then. Meanwhile, production in some basins, like the Permian in Texas and New Mexico, is within spitting distance of peak levels. While offshore rig workers around the world are packing up and heading home, oil companies are still drilling new wells in every major U.S. shale play. With this shift in oil resources, it’s no wonder major energy companies like BP are seriously examining how to best tap shale resources.
Why has U.S. shale production proven to be so resilient to low oil prices? I can think of (at least) three reasons. All three come down to costs. (Learn more in my “Off the Charts” podcast.)
First, as oil prices fell, so did the costs of drilling and completion services—more than 30% from the last quarter of 2014 to the first quarter of 2016. Because of this steep drop in costs, wells that would have been only marginally profitable in late 2014 could still be profitable in early 2016. Much of this decline in the price of drilling and completion services can be rationalized simply by supply and demand. When oil prices fell, shale producers had the ability to drive a harder bargain with their suppliers. After all, there was less of a “pie” to share in those negotiations, and there were fewer customers for oilfield service contractors to negotiate with. Thus, even without changing operating procedures or drilling locations, shale producers were partially insured against lower oil prices by a fall in the costs they faced.
Second, the engineering properties of shale wells mean that “breakeven” price calculations can be misleading about the profitability of new wells in a different oil price environment. While the development costs of conventional oil wells are mostly fixed in the form of drilling an expensive hole in the right place, more than half of the cost of developing a shale well lies in the complicated hydraulic fracturing treatment that producers must employ to make these wells productive. There is now long-standing evidence that more aggressive treatments generate more oil production. But since more aggressive treatments are more expensive, shale producers must solve a cost-benefit tradeoff: how much “fracking” maximizes the profits of a given well?
As we learn in Economics 101, the solution depends on both the price of output (oil) and the price of inputs (completion services). As oil prices fall, it is economically rational for shale producers to reduce the scale of their hydraulic fracturing treatments, because the marginal amount of oil generated by a marginal increase in the scale of the fracking treatment is less valuable than the cost of the treatment. Similarly, as service costs fall, it is rational to increase the scale of fracking treatments. Thus, a “break-even” price, often calculated as yesterday’s costs per well divided by yesterday’s expected production per well, will overstate the true price at which a shale producer would prefer to stop drilling completely.
Finally, shale producers are learning how to get greater bang for their buck out of drilling operations. As my colleague Sam Ori pointed out in an earlier post, producers have substantially increased the of total oil recovered in a typical well—from about 5% of the original oil in place to more than 12%. BP’s Chief Economist Spencer Dale predicts a 25% recovery factor might even be conservative five years from now. My research about the technical progress of hydraulic fracturing in the Bakken Shale of North Dakota shows that this is mostly explained by learning.
As shale producers tried more aggressive completion designs, they were able to figure out which designs offered the most oil production per unit of input cost. Over time, these companies learned better and better well designs, and in the process increased oil production per well by about 90% from 2005 to 2015. Even as oil prices collapsed, wells fracked in 2015 were still about 16% more productive than those in 2014. Importantly, I computed these productivity gains so that they are already net of the other “easy” gains oil companies in North Dakota realized by drilling longer wells in the most productive locations. Thus, the data shows that the recent collapse in oil prices has not prevented oil companies from continuing their learning process.
While cost reductions and unique engineering characteristics are important reasons for shale’s resiliency during a historic time in our energy landscape, learning and innovation provides the most hope for the industry’s future. As today’s shale producers continue to learn the most efficient ways of developing new wells, tomorrow’s producers in shale basins around the world will probably follow their lead. In doing so, the emergence of a nimble and innovating global shale industry will continue to frustrate conventional oil producers eager to return to tightly controlled production and higher prices.