U.S. shale oil production has peaked, productivity gains have flatlined and the cheap money has all but disappeared. Has the U.S. shale gale finally blown over?
BY TODD COYNE | follow Todd Coyne on Twitter
There’s something in the nature of revolutions that tends to make them simultaneously short-lived and prone to bringing about their own undoing. The U.S. shale oil revolution is no different. The technological advances in horizontal drilling and hydraulic fracturing unlocked millions of barrels of previously untouchable oil as they emanated out from a handful of Texas oil fields in 2007 like a wave. The wave gathered strength as it rejuvenated lackluster plays across North America and upended the international oil market. But while that wave lifted all the little boats of junior oil companies to brilliant new heights, it also rocked the dreadnought of OPEC, the world oil cartel that had weathered its share of price storms — and always come out the better — since the 1970s.
“The oil sands are still producing because they cannot just turn the switch off on a $20-billion project.”
– Farouq Ali
And so began shale’s undoing. In response to the flood of new North American oil coming to market in the past five years, OPEC producers opened wide the taps on their own production, putting into play all of the excess output capacity they had long held in reserve as a lever to control the world’s oil prices. U.S. crude production reached its 44-year peak of 9.6 million barrels per day in April 2015 before the eroding effect of low commodity prices began to lay down drill rigs and shut in wells, according to data from the U.S. Energy Information Administration. In its May 2015 forecast, FirstEnergy Capital estimated that U.S. oil supplies could fall by as much as one million barrels per day from that April high by the end of 2016, spurred by a major rollover in shale supply.
To summarize the damage: output has peaked, the cheap money and easy private equity are gone, the gains in per-rig productivity have slowed and the 20 to 30 per cent break that E&P companies were getting from contractors for labor costs won’t go on much longer. By all metrics, the shale party is nearly over. The question now is whether the 2015 production peak will forever be the high-water mark for this uniquely North American industry.
Most experts and analysts agree that, at current oil prices, the shale oil sector will need to dramatically reduce per-barrel costs in order to make the vast majority of North American plays viable. “The minimum price I’ve seen [to make production worthwhile] is $50 a barrel in the very best possible scenarios and with the very best technology,” says Farouq Ali, a chemical and petroleum engineer at the University of Calgary. “But most of the time they need $65 oil. So the 5.5 million shale barrels we see right now will all decline, but they will decline over time because there are still thousands of wells. Even if oil prices go to $60 they will still decline because that’s just not enough profit to operate.”
Of course, those returns aren’t just diminishing on the production side, but in the pocketbooks of investors, too.Wunderlich Securities senior vice-president Jason Wangler describes the rise of U.S. shales as a “perfect storm” of cheap money, seemingly limitless production potential and rapidly advancing technologies. “Now the money is hard to come by,” Wangler says over the phone from the firm’s Houston office. “With oil at $90 or $100 it was pretty hard not to be economic.” But that old high-price environment, he says, caused significant overinvestment in shale assets, including in risky bets on barely marginal plays like the Tuscaloosa Marine Shale formation that spans parts of Louisiana and Mississippi. “But if you look at the last year or so, you’ve seen a lot of folks really focus on the Permian and on the Niobrara,” Wangler says. “Meanwhile you’ve seen the Bakken really fall off very, very hard, as well as the Eagle Ford and the mid-continent area.”
The decreasing viability of the Bakken region is especially significant. Houston-based shale expert and petroleum geologist Arthur Berman estimates that with West Texas oil trading at $46, a mere one per cent of the massive Bakken shale play is profitable. At those prices, just four per cent of the horizontal wells that have been drilled in the Bakken since 2000 would recover their costs for drilling, completion and operations, according to Berman. Add to that the competition from Western Canadian crude oil, which continues to travel down through the U.S. Midwest via rail and pipeline, and one can assume that a lot of Bakken production will remain economically underwater without a significant price correction or some breakthrough in cost savings. “In the Bakken, you’ve got a long way to transport to get that oil to market,” Wangler says. “Obviously you’re fighting with all that Canadian crude coming down, which makes the price more difficult. It’s also expensive to [transport oil out of] North Dakota, whether you’re going to the Gulf Coast or you’re going east or west.”
However, unlike the oil sands, which are also getting hammered by low oil prices, the thousands of shut-in shale wells in the U.S. could technically be brought into full production again fairly quickly if prices rebound. But some argue that could further undercut any recovery for the energy sector in the short term by driving prices right back down again, in turn extending the slump. But the short term hasn’t looked very rosy in a long time, and those who are banking on – literally – the return of shale’s prominence would be wise to take a much longer view. “The oil sands are still producing because they cannot just turn the switch off on a $20-billion project,” Ali says. “So [the oil sands] will still be there, while the average decline in the life of a shale well is just five years. So with essentially the same amount of investment every time, it’s a case of highly diminishing returns.”
North Dakota’s Bakken production peaked last June at 1.15 million barrels per day before dropping down to 1.11 million by September, the most recent month for which state data is available. That production cut, when coupled with the Bakken’s higher transport costs, has led some U.S. East Coast refineries to return to processing foreign crude, an option that was less profitable than Bakken oil just a few years ago. That cycle is likely to continue for as long as OPEC maintains its current open-tap policy, taking a bite not just out of shale’s supply side, but out of its refinery demand market, too.
There’s no reason to believe, however, that the market for shale oil won’t see a revival eventually, according to one analyst. But it will likely be that the shale oil industry that we talk about in 10 to 15 years from now will have very little in common geographically and technologically with the one we talk about today. Whether that will mean a rebalancing of world oil markets and a diminished role for North American shales is anyone’s guess. James West, the senior managing director at New York-based investment advisory firm Evercore ISI, is hopeful. “If you look at the last four years before this one, oil was at $100 per barrel and the only place we were able to grow any production was in North America and in Saudi Arabia,” he says. “We clearly can’t grow production elsewhere around the world, so as long as we have economic growth and growth in demand for hydrocarbons, we’re going to need shale oil to grow.”
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