US oil and gas output rose during the third quarter of 2026, the Federal Reserve Bank of Dallas's quarterly Energy Survey reported, even as "price uncertainty plagues producers" across the surveyed operator panel.

The Dallas Fed's Q3 2026 Energy Survey polls exploration and production companies, oilfield service firms, and refiners across the Eleventh Federal Reserve District — Texas, southern New Mexico, and northern Louisiana. The latest release recorded an aggregate production increase alongside elevated concern over realized commodity prices.

What does the survey measure?

The Dallas Fed Energy Survey combines quantitative activity readings with qualitative commentary from company executives. Activity readings cover capital expenditure outlays, employment levels, and rig counts; sentiment components ask respondents about price expectations, cost trajectories, and operating conditions. The two streams feed the activity and outlook indices that have tracked district E&P health on a quarterly cadence for several years.

What did the activity readings show?

In the Q3 print, activity measures advanced while price-related uncertainty held the top position among constraints cited by respondents. The Dallas Fed compiles the survey four times per year and publishes results through its public site.

Why does the price-uncertainty reading matter?

Operators pointed to forward-curve shape, demand recovery timing, and the reliability of margin assumptions embedded in development economics as reasons to defer completion stages and hold capital programs under review. Respondents indicated that completion work had been pushed back or staged rather than executed on the original schedule, a pattern consistent with the price-sensitivity that has dominated operator commentary since the 2014-2016 downturn. The same constraint has appeared in earlier 2026 releases, indicating that the price concern is a persistent feature rather than a single-quarter spike. For service firms, the read carries direct commercial implications: frac and pressure-pumping pricing power remains limited while operators complete already-drilled wells rather than add new demand for crews.

Where did the production gain come from?

The Permian Basin, which sits inside the Dallas Fed's district and accounts for the largest share of US Lower 48 tight-oil supply, is the focal point of respondent commentary. Survey responses indicated that production gains came primarily from conversion of drilled-but-uncompleted well inventory rather than fresh drilling activity — a pattern consistent with operators monetizing sunk capital rather than adding incremental rig demand.

The Permian spans the Delaware and Midland sub-basins across West Texas and southeastern New Mexico. Survey commentary pointed to activity in both sub-basins, with the Delaware carrying the larger share of incremental production through Q3.

What did service and refining respondents report?

• Oilfield service respondents pointed to soft pricing across pressure pumping and completion spreads.
• Operators brought wells online using existing crews rather than expanding service procurement.
• Frac fleets and pressure-pumping capacity ran under-utilized through the quarter.
• Refiners reported compressed margins on feedstock cost pressure and uneven product demand.
• Gulf Coast complex operators noted uncertainty around international demand and product cracks.

What is the broader context?

The bank's district encompasses core US shale regions, including the Permian, Eagle Ford, and Haynesville producing regions across Texas, southern New Mexico, and northern Louisiana. The Q3 result aligns with the DUC-conversion pattern that survey respondents described.

What is the watch item?

The Q4 release, due in January, will test whether respondents add rigs into the December rig-count prints or keep working through the drilled-but-uncompleted inventory, and whether the price-uncertainty index retreats as forward-curve volatility narrows through year-end. The Q4 release will also be a key signal for service companies weighing capacity additions into 2027, and for Permian operators evaluating whether DUC inventory can sustain production growth into next year without an offsetting rig-count recovery.