US Oil Production and Oil Prices

Where US oil comes from

About four-fifths of U.S. crude comes from the onshore Lower 48 states, most of it from shale (tight oil) formations produced with horizontal drilling and hydraulic fracturing. The federal offshore Gulf of America (formerly the Gulf of Mexico) and Alaska supply the rest.

The Permian Basin

The Permian Basin of West Texas and south-east New Mexico is the engine of U.S. supply. The EIA estimates it produced 6.58 million b/d in 2025, 48% of the U.S. total, and expects it to account for most of the growth through 2027. Its two main sub-basins, the Midland and the Delaware, contain several stacked layers of oil-bearing rock, so producers can drill multiple wells from one pad. Permian crude is sold as WTI Midland, which since 2023 has also been part of the Brent price basket. See WTI Midland.

Shale breakevens: what price US producers need

The Dallas Fed's first-quarter 2026 Energy Survey, released on 25 March 2026, asked executives what WTI price they need:

• To profitably drill a new well: $66 per barrel on average, up from $65 a year earlier. The Permian average was $67, and regional averages ranged from $62 to $70.
• To cover operating expenses on existing wells: about $43 on average, with large firms needing about $32 and small firms about $46.

These numbers explain the two-tier response to prices. Below the mid-$40s, some existing wells are shut in. Between the low $40s and the mid-$60s, companies keep producing but slow drilling, and output gradually declines. Above the mid-$60s, drilling becomes profitable and output grows. With WTI averaging $97.31 in September 2026 (EIA spot), drilling economics are strongly positive. In the Dallas Fed's third-quarter 2026 survey, executives expected WTI at $88.38 on average at the end of 2026.

The rig-production lag

Higher prices do not raise output immediately. Companies first revise budgets, then contract rigs and completion crews, then drill, fracture and connect wells. The full cycle usually takes six to twelve months. The Baker Hughes rig count showed 462 active U.S. oil rigs on 9 October 2026, up from 418 a year earlier. The frac spread count, which measures completion crews, rose from 175 to 203 over the same period, according to Primary Vision data compiled by OilPrice.com. The EIA's forecast of 14.30 million b/d for 2027 reflects that activity.

Production has also become less sensitive to rig numbers. Longer horizontal laterals, faster drilling and better completion designs mean output in October 2025 was a record despite roughly a quarter of the oil rigs active at the 2014 peak.

How US supply caps oil price rallies

Before shale, a supply shock could keep prices high for years, because new conventional projects take five to ten years to develop. Shale shortened that cycle. When prices rise, U.S. output grows within a year, which tends to pull longer-dated futures prices down and keeps the futures curve backwardated. Producers also hedge by selling forward, which adds selling pressure in the later months of the WTI futures curve.

In 2026 this mechanism is visible but limited. U.S. production is up, and U.S. crude and products are flowing to Europe and Asia to replace Gulf barrels. The United States is a net exporter of petroleum, with net exports of 4.3 million b/d expected in 2026 (EIA). But the scale of the loss, with Gulf shut-ins peaking at 10.9 million b/d in May, is far larger than any plausible U.S. response. That is why the EIA expects prices to stay high until Middle East flows recover, not until U.S. output rises.

Two constraints also matter. Shale companies now prioritise shareholder returns: in the Dallas Fed's third-quarter survey, half of large producers said they would mainly return free cash flow to investors. And the best drilling locations in some basins are being used up, which raises costs over time. For OPEC+ strategy towards U.S. shale, see OPEC+ explained.