The Commodity Price Environment: 2025-2026 Outlook

Introduction

The commodity price environment is the single most important external variable for energy investment banking. Oil and gas prices drive E&P revenue, EBITDAX, NAV, reserve-based lending capacity, M&A activity levels, and the overall deal environment. Every energy banker must have a current, informed view on where commodity prices are, where they are heading, and what the key variables are that could move them in either direction. This article provides the 2025-2026 commodity price context that frames all energy banking work, covering crude oil, natural gas, and NGLs in detail before connecting the price environment to its implications for deal flow across sub-sectors.

The crude oil price environment in 2025-2026 has been marked by unusual volatility driven by the collision between fundamental oversupply trends and geopolitical supply disruptions.

2025 performance. Brent crude averaged approximately $69 per barrel in 2025, down from $81 in 2024. The decline reflected increasing non-OPEC+ production (US, Brazil, Guyana, Canada), slowing demand growth (particularly in China), and OPEC+'s gradual production increases. WTI averaged approximately $65 per barrel, with the Brent-WTI spread remaining in the $3-5 range. Most large-cap E&Ps remained free-cash-flow positive even at these levels due to improved capital discipline and lower breakeven costs.

Early 2026 spike. Brent surged above $94 per barrel in March 2026 following the onset of military action in the Middle East, as petroleum shipments through the Strait of Hormuz declined and some Middle Eastern production was shut in. This geopolitical risk premium added $20-30 per barrel to what underlying supply-demand fundamentals would suggest, demonstrating the market's sensitivity to disruptions in the world's most important oil transit chokepoint. Markets briefly priced Brent around $10 per barrel above fair value in mid-February 2026 due to anticipated US-Iran tensions, even before the disruption materialized.

OPEC+ Production Policy: The Unwinding of Voluntary Cuts

The most important supply-side variable for crude oil prices in 2025-2026 is OPEC+ production policy. Understanding the mechanics of the unwinding is critical for any energy banker advising on upstream transactions or building commodity price assumptions.

Eight OPEC+ members (Saudi Arabia, Russia, Iraq, Kuwait, the UAE, Algeria, Kazakhstan, and Oman) had been holding back approximately 2.2 million barrels per day in voluntary output cuts on top of the broader OPEC+ agreement. In early 2025, the group agreed to begin reversing these cuts over an 18-month timeline starting in April 2025, with full unwinding targeted by September 2026. The initial pace was cautious, but accelerated significantly through mid-2025, with monthly increases of approximately 411,000 barrels per day in May, June, and July 2025. By December 2025, the eight participating countries had unwound approximately 2.88 million barrels per day of the total cuts.

The unwinding has not been linear, however. On November 30, 2025, OPEC+ agreed to maintain production levels for Q1 2026 (January through March), pausing the incremental increases due to seasonal demand softness and concerns about global oversupply. This pause left approximately 1.24 million barrels per day of cuts still to be unwound. The stop-start nature of the unwinding creates significant uncertainty for energy bankers: at any given time, it is unclear whether OPEC+ will resume increases on schedule, extend the pause, or even reverse course and cut production again.

OPEC+ Voluntary Cuts vs. Mandatory Quotas

OPEC+ operates two layers of production management. Mandatory quotas are agreed upon by all OPEC+ members and set maximum production ceilings for each country. Voluntary cuts are additional reductions committed to by a subset of members (typically the largest producers) above and beyond the mandatory quotas. The voluntary cuts implemented in 2023-2024 and unwound in 2025-2026 are the primary swing variable for near-term oil supply. Because voluntary cuts are not formally binding, compliance varies: Kazakhstan and Iraq have repeatedly exceeded their quota targets, adding supply faster than the group intended and undermining the effectiveness of the cuts.

Saudi Arabia faces a strategic dilemma. Sustaining cuts defends prices but cedes market share to non-OPEC producers (especially US shale). Unwinding cuts recovers market share but risks crashing prices below the $85-95 per barrel fiscal breakeven Saudi Arabia needs for its diversification programs. The resolution of this dilemma will be the single most important factor determining whether Brent trades closer to $60 or $80 in the second half of 2026.

Non-OPEC Supply Growth: The Structural Overhang

Beyond OPEC+ policy, the fundamental supply-demand balance for crude oil is shaped by persistent non-OPEC production growth that continues to outpace demand. Global petroleum liquids production outside of OPEC+ grew by 1.8 million barrels per day in both 2024 and 2025, with US, Brazil, Guyana, and Argentina driving the bulk of the increases. Non-OPEC+ production growth is forecast to slow to approximately 1.0 million barrels per day in 2026, but this still exceeds projected demand growth.

United States. US petroleum liquids production increased by 0.6 million barrels per day in 2025 and is forecast to grow by another 0.5 million barrels per day in 2026. The Permian Basin remains the primary growth engine, though per-well productivity gains are slowing and the best core acreage is increasingly concentrated among a handful of large operators following the 2024-2025 megadeal wave.

Brazil. The scheduled start-up of two additional FPSOs in Petrobras's Buzios pre-salt field (one in December 2025, another in mid-2026) is expected to push Brazilian crude production up by approximately 0.2 million barrels per day to 4.0 million barrels per day on average in 2026. Brazil's pre-salt deepwater production benefits from low breakeven costs (often below $35 per barrel) and long-lived reserves.

Guyana. ExxonMobil's Stabroek Block continues its remarkable development trajectory. The start-up of the Uaru FPSO in 2026 is expected to add 250,000 barrels per day of production capacity, pushing Guyana's total output past 1.0 million barrels per day by 2027. Guyana's production growth of approximately 140,000 barrels per day in 2026 is significant because it comes at very low marginal cost and adds to the non-OPEC supply base regardless of price.

Argentina. Vaca Muerta shale is emerging as a meaningful source of non-OPEC growth, adding 50,000 to 80,000 barrels per day annually as pipeline infrastructure investments unlock previously bottlenecked production.

Demand-Side Variables

Global oil demand growth has decelerated from the post-COVID recovery pace. The IEA projects demand growth of approximately 930,000 barrels per day in 2026, down from 1.0 million barrels per day in 2025. The deceleration is driven by several structural and cyclical factors.

China's demand slowdown is the most significant headwind. Chinese oil demand growth has weakened as EVs surpass 50% of new car sales, the property sector downturn reduces diesel consumption, and the economy shifts toward services. China's incremental demand growth dropped from 1.5 million barrels per day in 2023 to under 0.5 million barrels per day in 2025.

EV penetration globally continues to erode gasoline demand growth in developed markets, though growing petrochemical feedstock demand and aviation fuel consumption (harder to electrify) partially offset this headwind. Emerging market demand in India, Southeast Asia, and Africa provides 0.4 to 0.6 million barrels per day of annual growth, primarily from transportation fuel and petrochemicals.

Forward Curve vs. Consensus Forecast

The WTI and Brent forward curves (the prices of futures contracts for future delivery months) reflect the market's real-time, tradeable price expectation. Consensus forecasts (aggregated from bank equity research teams and economic agencies like the EIA and IEA) reflect analyst judgment about supply-demand fundamentals. During periods of geopolitical disruption (like early 2026), the forward curve may embed a risk premium that consensus forecasts discount. Energy bankers typically use both as inputs: strip pricing for the first 2-3 years of NAV models and consensus for the long-term flat price assumption.

The Henry Hub natural gas market has experienced a dramatic recovery from record lows, driven by a combination of LNG export capacity expansion, AI-driven electricity demand, and producer supply discipline.

2024 trough. Henry Hub averaged a record-low $2.21 per MMBtu in 2024, reflecting the oversupply created by record US production (approximately 103 Bcf/d of dry gas) combined with a temporary pause in new LNG export capacity additions and mild winter weather that reduced heating demand. At these prices, gas-weighted E&Ps in the Haynesville Shale were operating near or below breakeven, and several producers curtailed drilling activity.

2025 recovery. Henry Hub rebounded 56% to average $3.53 per MMBtu in 2025 as several bullish catalysts converged. Plaquemines LNG Phase 1 began commercial operations in late 2024, Corpus Christi Stage 3 ramped in early 2025, and total US LNG gross exports reached 15.1 Bcf/d, up from approximately 12.5 Bcf/d in 2024. Simultaneously, data center power demand accelerated natural gas consumption for electricity generation, and producers maintained supply discipline in gas-weighted basins rather than flooding the market as they had in 2023-2024.

2026 outlook. The EIA projects Henry Hub averaging approximately $3.80 per MMBtu in 2026. LNG gross exports are forecast to grow 9% (approximately 1.3 Bcf/d) to 16.7 Bcf/d in 2026, driven by the continued ramp-up of Plaquemines LNG, Corpus Christi Stage 3 reaching full operations, and Golden Pass LNG beginning commissioning. On the demand side, power sector gas consumption continues to increase, driven by data center construction and coal plant retirements. However, supply growth is also keeping pace: domestic natural gas production is expected to increase by approximately 1.1 Bcf/d in 2026, partially offsetting the demand-side bullishness.

LNG Export Capacity: The Structural Demand Driver

The expansion of US LNG export capacity is the most important structural driver for Henry Hub pricing over the medium term. Each new liquefaction train that reaches commercial operations creates incremental, long-term demand for domestic natural gas, effectively providing a floor under Henry Hub prices that did not exist before the US became a major LNG exporter.

The current wave of LNG projects coming online between 2024 and 2027 will add approximately 10-12 Bcf/d of total export capacity, nearly an 80% increase from the 2023 baseline. Golden Pass LNG (2.4 Bcf/d, QatarEnergy/ExxonMobil JV) is expected to begin operations in 2026. Plaquemines LNG Phase 2 is on track for 2027. Beyond these, approximately 10 Bcf/d of additional capacity is in development, though some FIDs have been delayed by permitting uncertainty.

AI-Driven Power Demand: The Emerging Gas Catalyst

The second major structural driver for natural gas demand is the explosive growth in data center power consumption. US data center electricity demand is projected to grow from approximately 20 GW in 2024 to 50+ GW by 2030, with the bulk of this incremental load met by natural gas-fired generation. Hyperscaler companies (Amazon, Microsoft, Google, Meta) are signing long-term power purchase agreements with gas generators, effectively backstopping new gas-fired construction and locking in incremental demand for 10-15 year periods. This demand is price-inelastic: data center operators require reliable power regardless of whether gas costs $3 or $5 per MMBtu, making it structurally stickier than weather-dependent heating or industrial consumption.

Regional basis differentials remain an important analytical variable that directly affects how energy bankers model realized prices for E&P companies in different basins.

The Waha basis (Permian gas pricing relative to Henry Hub) continues to trade at a significant discount, often $1.00-2.00+ below Henry Hub due to associated gas oversupply relative to takeaway capacity. The Matterhorn Express Pipeline, which came online in late 2024, provided temporary relief, but growing Permian oil production (and its associated gas byproduct) continues to outpace available pipeline capacity. The next major tranche of Permian gas takeaway is not expected until 2027-2028, suggesting the Waha discount will persist.

The Dominion South basis (Appalachian pricing) has improved following the Mountain Valley Pipeline's completion in mid-2024, which added approximately 2.0 Bcf/d of takeaway from the Marcellus/Utica region, though Appalachian differentials remain negative. Gulf Coast basis premiums have strengthened as new liquefaction capacity creates concentrated demand near Sabine Pass, Cameron, and the Calcasieu/Plaquemines corridor in Louisiana, adding $0.10-0.30 per MMBtu above Henry Hub for producers with access to those delivery points.

NGL pricing in 2025-2026 presents a complex picture, with each component of the NGL barrel following its own supply-demand dynamics and price trajectory. For energy bankers advising on midstream transactions or gas-weighted E&P valuations, understanding NGL pricing is critical because NGL revenue often represents 15-25% of total wellhead revenue for liquids-rich gas producers.

Ethane. Ethane production reached record highs of 3.1 million barrels per day in early 2026, driven by growing Permian associated gas production and expanding ethylene cracker capacity on the Gulf Coast. However, domestic consumption has held steady at approximately 2.4 million barrels per day, creating a supply surplus that keeps ethane prices depressed. Ethane was trading near $0.11 per pound in early 2025, up 28.5% year-over-year but still well below levels that would incentivize ethane rejection (where producers leave ethane in the gas stream rather than extracting it). Exports have absorbed some of the surplus, reaching 534,000 barrels per day and projected to rise to 630,000 barrels per day in 2026 as international petrochemical demand grows.

Propane. US propane exports grew approximately 9% in 2025 compared to 2024, driven by Asian demand (particularly from China and India) and the displacement of Middle Eastern supply. However, the emergence of new Middle Eastern propane supply in 2026 (from expanded gas processing capacity in Saudi Arabia and Qatar) is expected to pressure global propane prices. Propane's pricing is anchored by its use as a petrochemical feedstock (propane dehydrogenation, or PDH) and heating fuel, making it the most seasonally volatile NGL component.

Butane and natural gasoline. Heavier NGL components (isobutane, normal butane, and natural gasoline) track crude oil prices more closely than lighter NGLs due to their use as blending components in the refining process. With crude oil prices elevated in early 2026 due to geopolitical factors, heavier NGL prices have strengthened, benefiting NGL-weighted midstream processors and fractionators at Mont Belvieu.

The relationship between commodity prices and energy deal flow is not linear. Different price levels trigger different types of transactions, and the direction of price movement often matters more than the absolute level.

Upstream M&A: The Price Sensitivity Matrix

For upstream M&A, the moderate oil price environment ($65-75 WTI) supports continued deal activity but at a less frenetic pace than the 2024-2025 megadeal wave. US upstream M&A totaled $65 billion in 2025, with $23.5 billion in Q4 alone, as private capital, ABS-backed buyers, and international investors intensified competition for assets. The deal themes have shifted from transformative mega-mergers toward mid-cap consolidation, bolt-on acquisitions, and portfolio rightsizing.

The geopolitical uncertainty widens the bid-ask spread on M&A transactions because buyers and sellers hold different views on whether the price spike is temporary or sustained. A seller may value assets at a $15-20 per barrel higher NAV using spot prices versus the strip, creating material gaps that slow deal execution.

Midstream and Power: Less Price-Sensitive but Still Affected

For midstream, the gas price recovery supports volume growth in gathering and processing systems, while LNG export expansion drives long-haul pipeline and LNG infrastructure investment. Midstream EBITDA growth of 5-10% annually is expected for most major operators through 2027. Midstream M&A remains strong as companies aim to secure infrastructure, processing, and export optionality tied to long-term gas and LNG demand growth. Fee-based contract structures insulate midstream operators from direct commodity price exposure, but volume throughput (which correlates with upstream activity levels) is still commodity-sensitive.

For power, rising gas prices (which increase wholesale electricity prices) combined with surging AI-driven demand creates a favorable environment for merchant power companies and nuclear generators. The Constellation/Calpine merger reflects the strategic value the market places on dispatchable generation. Higher gas prices benefit nuclear and renewable generators (zero fuel cost) by raising the marginal clearing price in wholesale power markets.

International Dimensions

The commodity price environment also affects energy banking outside the United States. In Europe, TTF natural gas prices remain structurally above Henry Hub (typically $8-12 per MMBtu versus $3-4 at Henry Hub) due to the continent's ongoing adjustment to the loss of Russian pipeline gas and its dependence on LNG imports. This trans-Atlantic price differential supports the investment thesis for US LNG export projects and creates advisory opportunities for cross-border gas supply transactions.

In the Middle East, NOCs (Saudi Aramco, ADNOC, QatarEnergy) continue to invest in capacity expansion despite lower prices, viewing market share as a strategic priority. Brent pricing is critical for Gulf state fiscal planning, as most require $65-85 per barrel to balance national budgets.