The oil industry is gathering in Houston for one of the biggest energy conferences of the year, and the question that will loom over CERAWeek by IHS Markit is just how fast can U.S. oil production grow?
The nation's output has surged to a 47-year high faster than anticipated, topping 10 million barrels a day in November and at least temporarily putting the United States ahead of Saudi Arabia as the world's second-biggest oil producer behind Russia.
Despite those achievements, investors still worry about the prospects for the nation's shale fields, where drillers have staged a renaissance in U.S. production by using advanced technology, like hydraulic fracturing, to free oil and gas from rock formations.
Plumbing oil from shale rock is a costly endeavor that depends on expert execution. Even then, production from shale wells peaks quickly and then begins a period of diminishing returns.
Raoul LeBlanc, vice president of financial services and North American onshore at IHS Markit, said he used to have to tamp down expectations about how much shale reserves could yield. Now he finds himself trying to calm investors rattled by any signs of trouble in drilling results from the nation's frackers.
"The market seems to veer back and forth between irrational exuberance and undue pessimism," said LeBlanc, who will moderate a panel of frackers at CERAWeek.
The question of America's oil growth prospects may boil down to logistics, cash and technology, according to LeBlanc.
The most immediate challenges facing the shale industry are bottlenecks for the services on which frackers rely. The key that unlocks shale drilling is hydraulic fracturing, the process of injecting water, sand and chemicals underground to fracture shale rock and let hydrocarbons flow to the wellbore.
A sharp recovery in drilling — following a drop in activity after the 2014 oil price collapse — has created a tighter supply of the crews that exploration and production companies employ to frack wells and has taxed the mines that provide sand.
Source: U.S. Energy Information Administration
These bottlenecks will present aggravations that potentially slow production growth over the next couple years, LeBlanc says. However, these are solvable problems and shouldn't impact the long-term growth prospects too much.
The industry also has to build out new pipelines and other transportation infrastructure to move oil from wells to market. The industry has seen a surge of opposition around megaprojects, like the Dakota Access and the Keystone XL pipelines, but LeBlanc said projects within oil-friendly states like Texas are unlikely to run into significant roadblocks.
But there is still a longer-term structural problem. Infrastructure companies typically need a roughly 30-year commitment to justify building a pipeline. That can be a risky endeavor in shale fields, where the decline rates of wells or a sudden exit of drillers from a region could impact how much crude is flowing through lines — and the profitability of expensive projects.
"There's a real mismatch between the risk profile of upstream players and the risk profile of midstream players," LeBlanc said, using industry terms for oil drillers and pipeline operators, respectively.
Over the next five years, the amount of cash that gets put to work in U.S. shale fields will play a major factor in future output.
Right now few drillers have assets that are good enough to produce cash sufficient to cover the cost of future production. That means frackers remain dependent on debt, equity and other types of outside capital to replenish rapidly depleting wells.
"It's the secret fuel for the shale revolution — the U.S. capital market and the ability to get lots of money very quickly," said LeBlanc.
U.S. shale regions
Source: U.S. Energy Information Administration
At least some flows could start drying up soon. Last year shareholders began signaling to drillers that they want to start seeing a return on their investments after years of debt fueled growth. Now more drillers are exercising tighter discipline and trying to fund growth with cash generated from operations.
If drillers start dialing back reinvestment, annual growth rates could look more like 200,000 barrels a day, with better returns for shareholders, rather than 1 million barrels a day, said LeBlanc.
Still, he believes capital will remain available. For one, private equity firms still have a lot of dry powder to invest. (Dry powder is money raised but not yet invested.) Also, oil giants like ExxonMobil and Chevron have pivoted to U.S. shale fields, and they may increasingly redirect money to those operations from more conventional projects in places like Nigeria and Kazakhstan.
While there is still plenty of shale oil to produce, drillers have already burned through the best acreage in some of the nation's shale fields, LeBlanc said. Other regions could soon be headed for what he calls "sweet spot exhaustion."
This is already playing out in some mature regions, like the Barnett Shale in Texas and the Fayetteville in Arkansas. In the coming years it could be a problem in North Dakota's Bakken and the Eagle Ford in southern Texas, LeBlanc said.
However, if technology can improve faster than rock-quality degrades, drillers can keep growing production and even lower the cost of extracting oil, according to LeBlanc. But if advances in technology can't keep up with the hollowing out of the best wells, then drillers won't be able to deploy cash efficiently.
"The thing that delays sweet-spot exhaustion is technology," LeBlanc said.
"That's going to determine whether you get growth through the 2030s or 2023."
Drillers weathered the three-year oil price downturn by securing discounts from service companies and moving their rigs to places where they could produce oil at low cost. At the same time, they've improved efficiency by drilling longer horizontal wells and fine-tuning the intensity of fracking.
The industry still has more levers to pull, and it's probably only in the sixth or seventh inning when it comes to how far the technology can advance, said LeBlanc.