Dallas Fed Survey: Drillers See $88 Oil While Spot Sits at $99

West Texas Intermediate crude averaged $98.70 per barrel during the window when the Dallas Fed collected its latest energy survey. The 125 executives who filled out that survey are forecasting the year will close at $88 per barrel.

That gap is the story. The people running the drilling programmes are looking at the price they are actually operating under and projecting a double-digit retreat before the year is out.

The Dallas Fed Q3 2026 energy survey, released on 30 September 2026, captured sentiment from 83 exploration and production firms and 42 oilfield services companies across the Eleventh District, which covers Texas, northern Louisiana, and southern New Mexico. It is a cleaner signal than any commodity headline, because it reflects how operators are positioning capital rather than how traders are pricing daily risk. The US-Iran war and the disruption to the Strait of Hormuz sit behind almost every number in it.

The Dallas Fed energy survey has evolved into a forward-looking capital allocation signal precisely because it captures operator sentiment before those decisions surface in quarterly earnings, giving institutional investors a roughly one-quarter lead on consensus estimates.

Here is what the survey data actually tells you about where E&P capital expenditure and oilfield services demand are heading through the rest of 2026 and into 2027, ahead of the moment those signals surface in quarterly earnings calls.

Growth is real, but the survey’s deceleration signal deserves attention

Activity is still expanding. The business activity index, the survey’s broadest measure of conditions across the sector, came in at 38.8 in Q3 2026. That is a firmly positive reading, and it confirms the Eleventh District is growing, not shrinking.

The trajectory is where the interest lies. The index sat at 21.0 in Q1 2026, jumped to 46.1 in Q2, then eased back to 38.8 in Q3. The direction of travel, not the absolute level, is the analytically useful signal here.

A decelerating index that stays well above zero is a slowdown story. It is not a contraction story, and that distinction matters for how you position, because it tells you the expansion is losing momentum rather than reversing.

The production sub-indices complicate the picture in a useful way. The oil production index rose from 15.0 to 20.7, and the natural gas production index climbed from 3.7 to 14.8. Physical output accelerated even as the headline confidence measure cooled.

That divergence is the read. Operators are pumping more barrels while growing more cautious about committing fresh capital, which is exactly what a late-cycle phase within an expansion looks like.

Rig count confirms the expansion, but rate-of-change tells a different story

Baker Hughes counted 599 total US rotary rigs for the week ending 25 September 2026, split between 455 oil rigs and 135 gas rigs. That is the highest total since 2024, and it sits 50 rigs above the equivalent week a year earlier.

The EIA Short-Term Energy Outlook for September 2026 placed national crude output on a trajectory that makes the Eleventh District’s rig count acceleration look even more consequential, given that the Permian Basin accounts for a disproportionate share of incremental US supply relative to other producing regions.

A rig count roughly 9% above year-ago levels reads as unambiguous strength on its own. Set it against the decelerating business activity index and the tension becomes visible: physical activity is still climbing while executive confidence has already turned.

For anyone assessing whether this rig count expansion is durable or approaching a near-term ceiling, the business activity index is the leading indicator to watch. A steadily softening index at still-positive levels is the tell that today’s rig growth may be borrowed time rather than a self-sustaining trend.

What the $70-to-$126 WTI forecast spread reveals about producer conviction

The average year-end WTI forecast among respondents is $88 per barrel. Taken alone, that number implies a settled view. The range around it says the opposite.

Individual forecasts ran from $70 to $126 per barrel. That is a $56 spread among people operating in the same basin, under the same cost structure, looking at the same conflict. When insiders that close to the physical market cannot agree within $56, the uncertainty itself is the finding.

The Strait of Hormuz disruption has compressed what would ordinarily be a multi-year demand signal into a single-quarter repricing event, which is why the $56 spread between the most bearish and most bullish respondents reflects genuine structural uncertainty rather than analytical disagreement.

The central tendency has firmed even as the spread narrowed. In Q2 2026, respondents averaged $81 per barrel with a range of $60 to $150. The upward move to $88 reflects tighter supply expectations as the Iran war’s effects persisted longer than some had assumed.

Respondents forecast a year-end range of $70 to $126 per barrel, while WTI averaged $98.70 per barrel during the very window they submitted those forecasts.

A $56 forecast spread among operators is not analytical noise. It tells you that no credible hedging programme or capital budget can rest on a single price assumption right now, and that the firms carrying the most price-sensitive cost structures are the most exposed if they get the call wrong.

Cost structure is the second variable sitting beneath the price uncertainty. Nearly 50% of respondents expect the diesel-to-crude spread to take more than four quarters to return to 2025 levels, against 36% who hold the same expectation for gasoline. Diesel feeds directly into drilling and completion costs, so a slow normalisation there squeezes margins independently of where crude settles.

On the gas side, Henry Hub is forecast to average $3.29/mmBtu by year-end, up from the $2.97/mmBtu average during the survey window. Even the gas market is recalibrating upward.

Dallas Fed economists Michael Plante, assistant vice president, and Kunal Patel, senior business economist, frame the survey. The risks clustered around the $88 average break into four buckets:

• Prolonged Strait of Hormuz disruption, pushing prices toward the top of the range
• OPEC+ production response, which could pull prices toward the lower end
• Demand destruction from sustained high prices or a macro slowdown
• US supply overshoot, where aggressive drilling brings more barrels to market than modelled

For anyone weighing E&P equities against oilfield services exposure, the range is more useful than the average. Companies hedged below $88 look conservative if prices hold near current spot; those that front-loaded capital expenditure on $90-plus assumptions face margin risk if prices converge toward the bottom of the range.

Why E&P firms and oilfield services companies are reading the same survey differently

Producers came through the Q3 survey more optimistic than oilfield services companies. Same basin, same commodity price, same conflict backdrop, two different outlooks.

This is not a temperament gap. It is a structural one, driven by two business models experiencing identical market conditions through opposite cost and revenue exposures.

Michael Plante noted that constraints on labour, equipment, and material delivery to oilfields may be limiting further activity increases. Those constraints do not land evenly. They fall disproportionately on the services side of the supply chain.

Three structural reasons the same market conditions produce different outlooks

1. Cost pass-through asymmetry. E&P firms capture higher prices directly, and the Q3 data confirms both oil and gas production indices rose. Services firms face rising costs for equipment, diesel, and labour while pre-agreed contracts limit how fast they can re-price. The result is margin compression even while upstream activity grows.
2. Supplier delivery-time risk. The survey explicitly flags longer supplier delivery times as a current condition. Extended lead times mean equipment delays, rescheduled jobs, and higher standby costs for services operators, eroding near-term earnings visibility even when order books look full.
3. The activity-to-pricing lag. Drilling authorisations move first. The business activity index swung from 21.0 to 46.1 to 38.8 across three quarters, showing how fast conditions can turn. Services firms re-price contracts a quarter or more after E&P firms commit programmes, so they can be locked into softer terms just as conditions cool.

The diesel spread compounds the second problem. With roughly 50% of respondents expecting more than four quarters before diesel-to-crude normalises, services operators running diesel-intensive fleets carry a cost headwind they cannot easily pass through.

The practical implication is direct. Two energy names listed on the same exchange, in the same basin, exposed to the same crude price, are not equivalent bets right now. The survey shows their near-term earnings trajectories are diverging, and it does so concurrently for both cohorts, making it a sharper relative-value tool than backward-looking earnings releases.

Oilfield services stocks are absorbing the structural divergence the survey captures, with capital beginning to rotate toward operators positioned in basins or contract structures that insulate them from the re-pricing lag that squeezes services margins in periods of rapidly changing upstream activity.

The Strait of Hormuz recovery timeline and what a Q2 2027 normalisation means for Eleventh District operators

The centre of gravity in executive expectations has already moved a long way. In the Dallas Fed’s Q1 2026 follow-up survey, the plurality expected the Strait of Hormuz to normalise by August 2026. By Q3 2026, the most commonly anticipated recovery had slid to Q2 2027, with a notable share expecting nothing before 2028.

That earlier distribution shows how quickly the consensus shifted, which is why the Q3 reading carries more weight than the Q1 one.

The most commonly anticipated recovery has moved from August 2026 in the Q1 follow-up survey to Q2 2027 in the Q3 survey, a full shift in the centre of executive expectation in a single quarter.

The recovery timeline feeds straight into how much new supply operators expect to add. When asked about the production response to the Iran war, 43% of respondents selected the band of more than 0 but not more than 0.25 mb/d. That points to incremental capital expansion, not an aggressive scramble, even at elevated prices.

A Q2 2027 normalisation expectation means the investment case for elevated Permian Basin activity rests on at least two more full quarters of sustained disruption premium. If you are pricing in a faster resolution, you are sitting on the optimistic tail of the executive distribution, not its centre.

The recovery timeline is the single variable with the most leverage over the entire WTI forecast range. Knowing where the median executive expectation sits, and how fast it has already moved, gives you a way to stress-test your own commodity price assumptions against the people running the actual drilling programmes.

For readers who want to stress-test the Q2 2027 consensus against a longer disruption scenario, our dedicated guide to the Hormuz recovery timeline examines the specific conditions under which normalisation accelerates or stalls, including insurance market signals and tanker routing data that precede official diplomatic announcements.

What the survey’s data actually changes for investors positioning into Q4 2026

Four threads run through this survey, and they point in the same direction. Activity is decelerating even as production climbs. The price forecast range is wide, with the average sitting well below current spot. E&P and services outlooks are diverging. And the Hormuz recovery has slipped to Q2 2027 in the space of two quarters.

Pulled together, the data reframes three questions worth carrying into the final quarter of the year:

• Is the rig count expansion durable through Q4, or is the softening business activity index the early signal of a ceiling?
• Is the current WTI spot price baking in a faster Hormuz recovery than the median executive expects?
• Does your energy exposure sit on the right side of the E&P versus oilfield services divergence?

The survey trajectory is the through-line. The business activity index moved 21.0, 46.1, 38.8 as your momentum indicator. The $88 per barrel average forecast against the $98.70 spot is your price stress-test. The Q2 2027 median recovery is your primary geopolitical variable.

None of this is a model output. The survey does not break out Permian-specific production volumes or name firm-level capital decisions, so the read is directional, not precise.

What it does offer is fresh. Conducted 16-24 September 2026 and published 30 September 2026, it is the most current institutional read on Eleventh District conditions available, drawn from 125 insiders with direct operational exposure. The edge sits in one recognition: the people running the rigs are more conservative on price and more uncertain on geopolitical resolution than spot prices currently imply.

This article is for informational purposes only and should not be considered financial advice. Investors should conduct their own research and consult with financial professionals before making investment decisions. Past performance does not guarantee future results. Financial projections are subject to market conditions and various risk factors, and forward-looking statements are speculative and subject to change based on market developments.