If the largest shale drillers kept their output roughly flat, as they have during the pandemic, many could continue drilling profitable wells for a decade or two, according to a Wall Street Journal review of inventory data and analyses.
If they boosted production 30 per cent a year – the pre-pandemic growth rate in the Permian Basin, the country’s biggest oil field – they would run out of prime drilling locations in just a few years.
Shale companies once drilled rapidly in pursuit of breakneck growth. Now the industry has little choice but to keep running in place. Many are holding back on increasing production, despite the highest oil prices in years and requests from the White House that they drill more.
The limited inventory suggests that the era in which US shale companies could quickly flood the world with oil is receding, and that market power is shifting back to other producers, many overseas. Some energy executives said concerns about inventory likely motivated a recent spate of acquisitions and would lead to more consolidation.
Some companies say concerns about inventories haven’t factored into their decisions to keep output roughly flat. For several years before the pandemic, frustrated investors had pressed companies to slow production growth and return cash to shareholders rather than pump it back into drilling. Companies have promised to limit spending, though some executives recently said high prices signalled a need for them to expand again this year.
US oil production, now at about 11.5 million barrels a day, is still well below its high in early 2020 of about 13 million barrels a day. The Energy Information Administration expects US production to grow about 5.4 per cent through the end of 2022.
Big shale companies already have to drill hundreds of wells each year just to keep production flat. Shale wells produce prodigiously early on, but their production declines rapidly. The Journal reported in 2019 that thousands of shale wells were pumping less oil and gas than companies had forecast. Many have since marked down how many drilling locations they have left. Some shale companies would eventually have to start spending money to explore for new hot spots, executives and investors said, and even then, those efforts were likely to add only incremental inventory. Few are currently doing so.
Pioneer Natural Resources, the largest oil producer in the Permian Basin of West Texas and New Mexico, raised its oil production between 19 per cent and 27 per cent a year in shale’s peak years. Now, Pioneer is planning to increase output only 5 per cent a year or lower, for the long term.
Scott Sheffield, chief executive of Pioneer, said the combination of investor pressure and limited well inventory meant he could not drill as he once did. “You just can’t keep growing 15 to 20 per cent a year,” he said. “You’ll drill up your inventories. Even the good companies.”
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Pioneer bought two smaller drillers last year, Parsley Energy and DoublePoint Energy, for almost $US11bn combined. Mr Sheffield said that with those acquisitions, his company has about 15 to 20 years left of inventory.
While privately held oil producers have increased their output in the Permian this past year, Mr Sheffield warned even the largest of those would drill through their inventory rapidly if they kept it up.
He expected US oil production to grow around 2-3 per cent a year, even if oil trades from $US70 to $US100 a barrel. US oil prices settled at $US88.26 a barrel on Wednesday.
Many drillers say they will never return to pre-pandemic production growth levels of up to 30 per cent a year, in part due to rising costs for raw materials and labour, a lack of financing and the enormous number of new wells it would require.
Five of the largest shale companies – EOG Resources, Devon Energy, Diamondback Energy, Continental Resources and Marathon Oil – all have about a decade or more of profitable well sites at their current drilling pace.
They would exhaust that inventory within about six years if they grew output 15 per cent a year, according to analytics firm FLOW Partners.
The Journal examined information about drilling inventories from analytics firm FLOW, Bernstein Research and energy consulting firm Rystad Energy. While each of the three made different assumptions, they all pointed to similar limits on inventory.
Some companies deny they are running low on prime wells, arguing FLOW had inaccurately labelled some of their better wells as uneconomic, among other reasons. Others said technological advances would allow them to extend the life of their acreage.
For years, frackers told investors they had secured enough drilling spots to keep going for decades. In 2018, Continental, which paved the way for a drilling bonanza in North Dakota’s Bakken field, said there could be 65,000 wells drilled there, producing 37 billion barrels of oil.
But to drill all those wells, Rystad said companies would have to explore the region further and improve on existing techniques, and it estimated the region could ultimately yield only as many as 28 billion barrels of oil.
The Permian is expected to be the longest-lived US oil region and is home to more than 80 per cent of the country’s remaining economic drilling locations, according to Wood Mackenzie.
