Selling conventional Permian assets, for upstream companies that still own them, might not only be a way to monetize assets with dwindling production that may now be non-core for majors or large independents, but also satisfy climate-change goals, analysts said.
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Since the advent of the shale oil revolution about a decade ago, the conventional Permian – vertical, relatively lower-output wells that have in many cases produced for decades – is no longer a main focus for many producers in the West Texas/New Mexico play.
"The deal market has recovered somewhat, so the timing might be right" for larger E&P companies to sell conventional Permian assets that they have held for many years, said Artem Abramov, partner and head of shale research for consultants Rystad Energy.
Moreover, reducing their carbon footprint as the upstream oil and gas sector grapples with its role in the energy transition to cleaner and alternative fuels may be an added incentive to sell operations with higher emissions, observers say.
"While certain enhanced oil recovery efforts are economically viable ... it would be hard to maintain competitive greenhouse gas intensity" while holding onto conventional wells, Abramov said.
Over the life of a well, its marginal carbon intensity increases "significantly" as it produces increasingly less oil, said Parker Fawcett, North American supply analyst for S&P Global Platts Analytics.
"Also, significant methane leaks relative to production levels occur due to the facilities not having the latest equipment and technologies" to eliminate or avoid emissions into the atmosphere, Fawcett said. "If an operator, say a major, was looking to improve their methane or carbon intensities, selling legacy conventional production would be a solid place to start – especially with federal methane regulations possibly being expanded ... in the near future as ordered by the Biden Administration," he said.
High liability costs of old wells
High liability costs from plugging and abandonment might also prompt conventional asset sales that are nearing end-of-life or that may have adverse economics from potential new regulations, Fawcett added.
Recently, Chevron said it planned to sell its Permian conventional assets, where the major and its legacy companies have produced for nearly a century.
Other E&P companies with sizeable conventional Permian holdings include Occidental Petroleum, Apache Corp, Pioneer Natural Resources, ConocoPhillips and ExxonMobil.
Conventional wells are essentially older wells drilled vertically that each produce much less than sophisticated horizontal wells of more recent vintage.
The nearly 80,000 conventional Permian oil wells are low-yield by current standards at an average of about 4-4.5 b/d, according to Abramov. In contrast, the most productive wells in the play have come on at rates of 3,000-4,000 boe/d.
Still, the conventional Permian, which produces a total of roughly 500,000 b/d of oil, a fraction of the play's current output of 4.5 million b/d, continues to be a viable asset for dozens of small private companies.
Private equity could fund new players
While small private E&Ps might seem logical buyers for conventional assets, some of those operators may not wish to bulk up in size or don't have the balance sheet for a pricey acquisition.
But new well-funded startups might offer both financial backing and a desire to grow, Abramov said.
"I do not think we will see any smaller pure unconventional Permian players expanding their portfolios," Abramov said. "It is more likely that we will see some new private equity programs – i.e., brand new entities – formed specifically to take over ... conventional assets" in the Permian.
Some assets might even change hands among majors or large independents, he said.
While Reuters in June quoted sources saying Chevron's conventional assets might fetch upwards of $1 billion, Abramov estimated a total of $8-9 billion as a "fair" price for the entire Permian conventional portfolio among operators that might want to sell.
Around 2010, operators' success in drilling vertical natural gas shale wells outside the Permian and then taking them horizontally for a few thousand feet to access more productive hydrocarbons was paying off. Companies found that hydraulically fracturing the laterals at regular intervals led to initial output rates many times that of vertical wells – and found they could use these techniques for oil as well as gas wells.
At first, 1,000 boe/d was a typical initial output rate for a completed shale oil well, but this later became 2,000 boe/d, 3,000 boe/d, and sometimes more as operators drilled longer laterals – a well's horizontal portion – and employed more and better techniques to coax increasing volumes from the rock.
During the 2020 pandemic, as US producers curtailed uneconomic shale production from very low oil prices, about 10,000 conventional Permian wells were shut in and never returned, resulting in about 80,000 b/d of permanently lost output.
Wells drilled in the play before the 1960s still produce over 15,000 b/d, while wells drilled in the 1960s account for about 20,000 b/d; in the 1970s, 40,000 b/d; 1980s and 1990s wells nearly 50,000 b/d each decade, Fawcett said.
At about 175,000 b/d, "that's still a lot of production from wells not even drilled in this century," he said.