2026 Outlook: Our Annual Forecast Issue
Every December we run the numbers and tell you what we actually think. Not what consensus says, not what the Street is pitching, but an honest read on where U.S. upstream is headed. Here is the 2026 edition.
The Macro Backdrop
WTI averaged roughly $73 per barrel in 2025 — a year that opened with moderate optimism and spent most of its time frustrating both bulls and bears. OPEC+ continued its production management strategy, Saudi Arabia extended voluntary cuts into H2, and U.S. production continued its slow march higher, exiting the year near 13.6 MMbbl/d according to EIA weekly estimates. Neither a crash nor a rally materialized. That is the 2025 story in one sentence.
For 2026, our base case is a WTI range of $65–$80, with a midpoint around $72. Global demand growth will remain modest — the IEA projects roughly 1.0–1.1 MMbbl/d of net demand growth, driven almost entirely by emerging Asia. Demand from OECD economies is effectively flat. That demand profile is not enough to tighten the market meaningfully unless OPEC+ holds discipline, which has become less certain with every passing quarter.
Supply: U.S. Production Outlook
The big upstream question for 2026 is whether the Permian can continue growing at a pace that keeps U.S. output on an upward trajectory. Our answer: yes, but slower. Basin exit rate for 2025 was approximately 6.4 MMbbl/d. We model 6.6–6.8 MMbbl/d by year-end 2026 — meaningful growth, but the torrid 300–400 Mbbl/d annual gains of 2022–2023 are behind us.
Tier 1 inventory is not exhausted, but the best rock is increasingly concentrated in fewer operators' hands following the merger wave of 2024–2025. ExxonMobil, Chevron, ConocoPhillips, and Diamondback Energy collectively control an outsized share of remaining high-return Midland and Delaware Basin inventory. Their capital discipline translates to measured, not aggressive, growth. We expect the combined Permian operators to hold combined capex roughly flat to 2025 levels.
Outside the Permian, the growth story is largely absent. The Bakken will produce near its plateau of 1.25–1.30 MMbbl/d. Eagle Ford will hold near 1.1 MMbbl/d with modest downside risk. The Niobrara/DJ continues its mid-400 Mbbl/d range. None of these basins have the inventory depth or operator appetite to drive incremental barrels at current prices.
Natural Gas: The Recovery Thesis Gets Tested
Gas is where the 2026 debate gets interesting. Henry Hub averaged roughly $2.25/MMBtu through most of 2025, punishing producers who were counting on LNG-driven demand to absorb Appalachian and Haynesville volumes. The recovery trade — which we have discussed in this publication repeatedly — finally began materializing in late Q4 as storage deficits emerged and LNG exports ramped.
Our 2026 Henry Hub forecast: $3.00–$3.75/MMBtu average, with upside risk in the winter months if storage enters Q1 lean. Sabine Pass Train 7, Plaquemines LNG Phase 1, and the ramp of Corpus Christi Stage 3 collectively add meaningful export capacity in the 2025–2026 window. Those volumes pull approximately 2.5–3.0 Bcf/d of incremental demand from the domestic market. For Haynesville and Appalachian producers, that is the difference between breakeven and a profitable quarter.
Rig Count and Capital Discipline
Baker Hughes ended 2025 with approximately 580 active land rigs — essentially flat to year-ago levels. We do not see a meaningful rig count expansion in 2026 absent a sustained move above $80 WTI or $4.00 Henry Hub. Operators have learned to do more with less, and the efficiency narrative is real: lateral lengths continue extending, cycle times are compressing, and completion designs are pushing the envelope on proppant intensity.
Industry E&P capex for 2025 is estimated at approximately $135 billion — roughly flat to 2024. Our 2026 estimate is $130–$140 billion, with a slight downward bias if oil prices soften. The majors and large-cap independents have been explicit: return of capital, not production growth, is the priority. That message has not changed.
Key Risks and Wildcards
To the downside: a demand-driven macro shock, meaningful OPEC+ quota violations by members facing fiscal pressure (Russia, Iraq, UAE), or a warm winter that leaves U.S. gas storage elevated into spring. Any of these scenarios compresses the commodity stack and tests operator discipline.
To the upside: a cold winter that draws storage sharply, a geopolitical event that removes barrels from the market, or an LNG demand spike from Europe/Asia. The upside scenarios are real but not our base case.
The structural story remains intact. U.S. shale is a swing producer. Operators are better at capital allocation than at any point in the last decade. The question for 2026 is not survival — it is how much growth the market will fund at these prices.
CIR will revisit this forecast quarterly. Our next check-in is the Q1 2026 Rig Count and Activity Update.
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.
