2026 Budget Season Wrap: Industry Capex Totals
The 2026 capital budget cycle has largely completed, with most major E&P operators releasing preliminary budgets at their analyst days and investor conferences through November and December. The headline number: the U.S. upstream industry is set to spend approximately $130–$140 billion on exploration and development in 2026, roughly in line with 2025 actual spending.
That flat-to-slight-decline spending profile tells you everything you need to know about where we are in the cycle. Companies are not pulling back from their assets — the economics still work at $70 WTI — but they are not expanding activity either. Capital discipline, now three years running, has become the industry's defining characteristic.
The Big Spenders
ExxonMobil is guiding to $28–$33 billion in upstream capital globally for 2026, with a significant portion directed at Permian operations and Guyana development. Domestically, XOM's Permian budget is estimated at $5–$6 billion, sustaining roughly 400–450 net drilling locations per year in the combined Pioneer/XOM acreage position.
Chevron guided to $14.5–$15.5 billion of global upstream capex, with its Permian allocation holding near $4.5 billion. Chevron has been deliberate about Permian growth pacing — CEO Mike Wirth has consistently said the company will grow Permian output to approximately 1.0 MMBoe/d by the end of the decade, but not faster.
ConocoPhillips is guiding to approximately $12.9 billion in total capital, with increased allocation to the Permian following the Marathon acquisition. COP's multi-basin portfolio — Permian, Bakken, Eagle Ford, Alaska, and Montney — provides natural diversification that buffers against single-basin commodity price swings.
Diamondback Energy guided 2026 capital to approximately $3.8–$4.2 billion, sustaining production in the 475,000–485,000 Boe/d range. CEO Travis Stice has been consistent that Diamondback will not grow for growth's sake — the company runs maintenance capital plus a modest growth component that generates maximum per-share free cash flow.
The Independents: Discipline Holding
Mid-cap independents broadly held their capital frameworks flat. Devon Energy guided $3.4–$3.8 billion, reflecting the integration of its Williston Basin acquisition and sustained activity in the Delaware Basin. Coterra Energy guided $2.1–$2.3 billion, maintaining its mix of Permian, Marcellus, and Anadarko drilling.
The natural gas independents — EQT, Expand Energy, Range Resources — guided flat to slightly down on activity, consistent with their stated strategy of prioritizing per-unit cost reduction over volume growth in a recovering but not yet robust gas price environment. EQT's guidance implies approximately 5.6–5.7 Bcf/d of production at modest capex levels, underscoring just how efficient Appalachian well economics have become.
The Oilfield Services Read-Through
Flat operator budgets translate directly to flat oilfield services demand. Halliburton, SLB, and Baker Hughes have all guided to North American revenue roughly in line with 2025 actuals — no growth, but no collapse. Pressure pumping utilization sits in the mid-70% range, a level that does not incentivize major capacity expansion by service companies.
Pricing for oilfield services has been under pressure since Q2 2024 as operator efficiency gains reduced the amount of service intensity per well. A lateral that now takes 18 days to drill instead of 25 uses less rig time, less mud, and fewer bit runs. That efficiency improvement is great for operator economics but creates real pricing pressure for service companies whose revenue is fundamentally time-and-material-based.
What Would Change Budgets?
Sustained WTI above $80 per barrel would likely prompt mid-cycle budget adjustments from several operators who have telegraphed conditional activity expansion. Devon Energy has said explicitly that above $80 WTI, it would consider adding a rig in the Delaware Basin. Coterra has similar language. The price level that triggers activity expansion is well-known; the question is whether the price will get there and stay there long enough to justify the commitment.
To the downside, a move below $65 WTI would likely trigger budget reductions, led by single-basin operators in higher-cost plays. The Bakken and Eagle Ford are more price-sensitive than the Permian at the margin; those are the basins to watch for first signals of activity contraction.
For now, $130–$140 billion of E&P capex sustains roughly flat-to-modest growth in U.S. production. That is exactly the outcome the industry said it would deliver, and for once, it appears poised to do exactly that.
Crude Intelligence Report is an independent upstream oil and gas intelligence publication. Content is for informational purposes only and does not constitute investment advice, financial advice, or a recommendation to buy or sell any security. Always conduct your own due diligence before making investment decisions. The author and publisher hold no positions in any companies mentioned in this article. © 2026 Crude Intelligence Report. All rights reserved.
