All that new shale oil may not be enough as big discoveries drop
Three years after causing an oil-price crash, the shale boom may not be enough to meet rising global demand because the industry has cut back so sharply on higher-risk mega-projects.
Discoveries of new reserves this year were the fewest on record and replaced just 11 per cent of what was produced, according to a Dec. 21 report by consultant Rystad Energy. While shale wells are creating a glut now, without more investment in bigger, conventional supply, the world may see output deficits as soon as 2019, according to Suncor Energy Inc.
“Tight rock is not going to solve the global supply-demand issue,” said Adam Waterous, chief executive officer at the Calgary-based Waterous Energy Fund, which invests as much as $400 million. “Its going to take a long time for those mega-projects to come back on.”
Fracking made it possible to squeeze crude from tight-rock formations and turned the U.S. into the world’s top producer. But it also sent the global benchmark for oil tumbling from $115 a barrel in 2014 to less than $55 in October. That’s eroded the incentive for companies to invest billions of dollars on new reserves that take years to develop but can produce for decades.
Oil prices would need to climb to $80 and remain at that level for two years to justify the costly deepwater projects off the coasts of West Africa or Brazil, Waterous said. And even then, it could take a decade before crude from those investments would arrive on the market, he said. Prices topped $66 this week.
For now, producers have set their sights on smaller, less-risky reserves. In 2013, when investment was peaking and prices were comfortably above $90, the industry was starting new projects that typically targeted reserves of 1.1 billion barrels and cost $9 billion each, according to a January report by consultant Wood Mackenzie Ltd. By 2017, projects on average were expected to shrink to 500 million barrels each and cost $3 billion.
That’s primarily because fracking of North American shale formations in places like Texas and North Dakota has transformed the industry.
Companies like Royal Dutch Shell and Exxon Mobil historically invested tens of billions of dollars over many years to develop huge reserves in isolated areas like Alberta, Kazakhstan or in the middle of the ocean.
Shale is different. A tight-oil well could be drilled within a year for a few million dollars. As prices fell, more companies jumped in with more investment.
Now, shale regions that were barely a blip on world markets a decade ago are expected to pump 7.5 million barrels a day in four years, and output probably won’t peak until after 2025, according to the Organization of Petroleum Exporting Countries.
But as robust as U.S. shale oil has been and will continue to be, those reserves alone face a “daunting task” keeping pace with growing global demand if approvals of conventional projects don’t pick up, the IEA said in September. Earlier this year, researchers at the Massachusetts Institute of Technology said the U.S. government may be overstating future growth in shale output because of flawed assumptions about oil technology.