By Shale Markets · Tuesday, September 29, 2026 · 5 min read

Spending Shift to Existing Wells Raises Risk of Faster U.S. Shale Output Drop

Original illustration created for Shale Markets.

Spending Shift to Existing Wells Raises Risk of Faster U.S. Shale Output Drop

A rig count that rose 44 in three months

Baker Hughes put the total U.S. oil and gas rig count at 588 for the week ending July 31, 2026, according to EnergyNow.com's report that day — the only account of that week's count located, and not separately confirmed against Baker Hughes' own published series. The same report tracked the Utica rig count at 11, the lowest since May 2025, in a basin where gas realizations, not oil economics, drive the drilling decision.

The EIA's own November 17, 2025 assessment argues the rig count no longer tells the story it used to. Natural gas-directed rigs fell to 96 in late 2024 amid what the agency called "historically low and prolonged natural gas prices," yet output held up because of what the EIA describes as improved production efficiencies. For 2026, the agency forecasts Lower 48 crude output will decline slightly, by 0.1 million barrels a day, or roughly 1%, as operators prioritize maintenance work over new drilling.

Capex is down, and mostly going to existing wells

RBN Energy's April 8, 2026 analysis of 36 E&P companies, a sample RBN did not itemize by name, put 2026 capital investment at $59.1 billion, down 5% from $62.5 billion in 2025 and off the 2023 peak of $64.5 billion. The firm frames the drop as a continued shift toward shareholder returns rather than reserve replacement, with producers leaning on efficiency gains to offset the steep decline curves inherent to shale wells.

TD Cowen's April 2026 survey, cited in BOE Report's April 24 coverage of that week's rig data, found E&Ps planning to spend roughly 1% less in 2026 than in 2025, following a 4% cut the year before.

The cuts have landed hardest at large-cap operators, according to a single account: Transport Topics reported on August 14, 2026 that Chevron and ConocoPhillips reduced Lower 48 capital expenditure by 10% in the first half of 2026, while Occidental cut Permian spending by 20% over the same period. The same article put total U.S. crude supply growth for the year at roughly 200,000 barrels a day — a broader, national figure that is not directly comparable to the EIA's Lower 48-only forecast of a 0.1 million barrel-a-day decline cited above; the two describe different scopes.

DUCs instead of drilling

Kpler's June 15, 2026 note on the stall in shale growth during the second quarter identifies drilled-but-uncompleted wells as the mechanism keeping barrels flowing without new capital commitments. DUCs can be brought online faster and at lower cost than a fresh well. Kpler describes operators drawing on that inventory rather than restarting rigs even as crude prices sit in a range that would once have justified expansion, but the note does not publish an inventory level or a drawdown rate, so how much runway that supply has is not established.

East Daley Analytics, in a March 14, 2026 report, ties the reluctance to a structural constraint rather than pure caution: limited natural gas takeaway capacity out of the Permian is blunting the supply response to higher oil prices, and the WTI forward curve's steep backwardation — with fourth-quarter 2026 prices expected well below spot — gives operators little reason to add rigs even where gas egress isn't the binding issue.

Diamondback's exception

Not every operator is retreating identically. Diamondback Energy raised its 2026 production guidance to more than 520,000 barrels a day and increased capex by 4% to preserve operational flexibility, according to ETF Database's June 23, 2026 summary of the company's first-quarter results — the only account of that guidance change located. The company also moved away from a fixed quarterly shareholder return to retain cash for Permian operations, a departure from the industry's dominant pattern of returning capital rather than reinvesting it.

EnergyNow.com reported on September 28, 2026 that Diamondback, Coterra Energy and Ovintiv all planned modest output increases for late 2026 despite prices sitting near break-even. Ben Hoff of Societe Generale told the outlet the industry has become a "technology story," using drilling and workover advances to hold barrels flat while cutting costs, which he described as the industry finally tackling the "other side of the ledger."

What sub-$3 gas does to the Utica and the Permian

Utica rigs at 11 as of July 31, 2026 sit against a basin where gas price realizations, not oil economics, drive the drilling decision, and that low a count leaves little cushion if Appalachian decline curves behave the way the EIA describes for Lower 48 oil wells generally, with fast initial drop-offs that require continuous new-well activity just to hold flat.

The Permian's exposure runs through a different channel. East Daley's March report identifies gas takeaway capacity, not price, as the binding constraint there, so new oil wells that would otherwise pencil out at current WTI levels get held back by associated-gas bottlenecks rather than by the wellhead economics of the oil itself. Occidental's 20% Permian cut and Chevron and ConocoPhillips' 10% Lower 48 reductions, both reported by Transport Topics in August, suggest the largest operators are treating gas takeaway limits and capital discipline as reasons to hold rather than expand.

The arithmetic operators are running against

Diamondback's decision to raise capex 4% while its peers cut is the clearest signal that at least one large operator is planning past its own DUC inventory. Whether the rest of the Lower 48 follows before decline curves force the issue is the question the rig count alone will not answer.

Links Verified at Time of Publish.