As industry watchers eye the U.S. oil and gas sector’s shrinking DUC count and natural declines, wondering what the future holds for drilling in shale plays, analysts say operators must spend more in 2022 to keep production from falling.

If oilfield inflation continues and hits well costs, they may have to shell out even more.

“If a public E&P is exposed to say 7% inflation and say 14% loss from end of DUC subsidy, a >20% rise in capex would deliver a comparable completion level as 2021,” Bernstein analysts said in a note this week. “We think signaling such a rise in capex with relatively little benefit (or a 30% rise in capex to achieve say a 5% production growth) would be met poorly with investors.”

Other issues to consider include the impacts of fewer E&P and service company staff available to carry out work, incentives for E&P management teams to limit spending and potential inflation up to 10%, Bernstein analysts said. The industry has already seen some inflationary pressure in areas such as diesel, steel and other materials plus labor.

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Bernstein’s analysis was delivered as developers of shale oil and gas assets focus on completing drilled wells, which have driven U.S. production growth recently. However, the DUC inventory has dropped to about 5,000 from about 8,000, analysts say.

The shrinking DUC inventory could limit oil production growth in the coming months, the U.S. Energy Information Administration (EIA) said in September. At that time, DUCs in the Bakken, Eagle Ford and Niobrara regions had sunk to their lowest levels since December 2013, while DUCs in the Permian and Anadarko basins had dropped to levels not seen since June 2018.

Data dating back to August 2020 show completed wells have outnumbered wells drilled every month for major oil- and gas-producing basins tracked by the EIA.

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Completing DUCs has allowed producers to maintain production without spending more and adding rigs, but they might have to find the happy medium to appease investors: balancing priorities of capital discipline, shareholder returns and efficiencies against drilling more new wells to grow supply at higher oil prices to increase profit.

Given the “dead DUC double-digit headwind,” Bernstein analysts said they estimate the industry would have to spend about 14% more capex in 2022 without the DUC subsidy to complete about 7,000 wells over the next 12 months. The analysts estimate wells cost about $7 million, which includes about $5 million for completion work and $2 million for drilling.

There were some caveats. Higher oil prices and hedges were among the concerns.

Oil prices have rebounded from historic lows, with West Texas Intermediate near $78/bbl on Oct. 6. Rising prices could enable producers to spend more on drilling while increasing shareholder payouts. Bernstein has said that shale players could reinvest about 50%-60% of cash flow, at $73 WTI, and remain in the “safe zone.”

Which companies opt to raise spending in 2022 and by how much remains to be seen. The upcoming earnings season in November could shed some light on potential indicators.

Growing cash flow remains among the top priorities for E&Ps.

“Clearly high prices generate significant additional cash flow,” analysts said. “E&Ps are generating sufficient cash flow to grow spending.”

Add to this the ability for public E&Ps to lock in strong hedges, the analysts noted.

However, “Again, just because they generate a lot of cash flow doesn’t require that they spend it.”

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