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, and M&A activity, so every energy banker needs an informed view on where prices are heading and what could move them. The 2025-2026 period tested that view hard. An oil market that entered 2026 braced for a supply glut was hit instead by a supply shock when the Strait of Hormuz, the route for roughly a fifth of the world's oil, closed after war broke out on February 28, while US natural gas stayed soft despite record LNG exports. This article covers what crude oil, natural gas, and NGLs actually did, how OPEC+ and governments responded, and how bankers choose the price deck under every valuation. The war itself is told in The Strait of Hormuz Crisis: The 2026 Energy Supply Shock; this article stays on prices.
Crude Oil: From Expected Glut to Supply Shock
The crude oil market spent 2025 pricing a surplus and most of 2026 pricing a shortage, which is why two price decks built a year apart can disagree by more than $30 per barrel. Brent averaged about $69 per barrel in 2025, down from $81 in 2024, according to the EIA's October 2026 Short-Term Energy Outlook. The decline reflected rising non-OPEC+ production, slowing Chinese demand, and OPEC+'s gradual production increases. WTI averaged about $65, with the Brent-WTI spread in the $3-5 range, and most large-cap E&Ps stayed free-cash-flow positive thanks to capital discipline. Brent still averaged only about $67 in January 2026 and $71 in February.
The 2026 shock. US and Israeli strikes on Iran began on February 28, and Iran answered by attacking tankers and Gulf energy infrastructure, all but closing the Strait of Hormuz. Brent, about $72 on February 27, rose 51% in March, one of the largest one-month gains on record. The IEA's record 400 million barrel emergency stock release, agreed on March 11 and more than twice the size of the 2022 release, did not stop Brent futures closing above $100 the next day for the first time since August 2022. From there, prices followed the war's phases:
- Peak and ceasefire (March to April). Dated Brent, the physical benchmark, peaked at about $138 on April 7 in the EIA's daily spot series. The two-week ceasefire announced that evening knocked more than 10% off prices, but the strait stayed largely shut, and dated Brent still averaged about $117 in April and $107 in May.
- Partial reopening (May to early July). As tanker traffic resumed after a US-Iran deal in June, dated Brent fell to about $68.5 on July 2, its wartime low and below its pre-war level.
- Second shock (summer to October). Renewed attacks, including strikes on Saudi Arabia's East-West pipeline (the main Hormuz bypass), sent dated Brent to $131 on September 15. On October 16, Brent futures settled at $109.86 and WTI at $101.41 as Iran escalated attacks on shipping in the strait.
Two features of this path matter more to bankers than any single print. The first is the physical premium: the IEA's October 2026 Oil Market Report put Brent futures around $107 while North Sea Dated traded near $134, the gap between a barrel available now and one delivered later. The second is a wider Brent-WTI spread (more than $8 on futures in mid-October), because Brent prices the seaborne barrels the closure removed while WTI is anchored in a domestically supplied US market.
OPEC+ Production Policy: From Unwinding Cuts to Stranded Barrels
OPEC+ policy was the most important supply variable going into 2026. Eight members (Saudi Arabia, Russia, Iraq, Kuwait, the UAE, Algeria, Kazakhstan, and Oman) had been holding back about 2.2 million barrels per day in voluntary cuts on top of the broader agreement. They began reversing them in April 2025, accelerating to monthly increases of about 411,000 barrels per day from May, then on November 30, 2025, paused increases for Q1 2026 on oversupply concerns.
The war made quotas largely academic: barrels that cannot pass Hormuz cannot be sold. The EIA estimates Middle East production shut-ins peaked at 10.9 million barrels per day in May and still averaged 4.8 million barrels per day in September (EIA global oil outlook). OPEC+ kept raising targets through much of 2026, but Gulf members pumped well below them. Two breaks followed:
- The UAE's exit. The UAE left OPEC and OPEC+ effective May 1 after 59 years, citing its national interest amid tension over a 3.5 million barrel per day quota that sat well below the roughly 5 million barrels per day of capacity it has built.
- A holding pattern. The seven remaining members of the voluntary-cut group kept November targets unchanged at a combined 31.01 million barrels per day at their October 4 meeting, after holding October flat as well.
- OPEC+ Voluntary Cuts vs. Mandatory Quotas
OPEC+ operates two layers of production management. Mandatory quotas are agreed by all OPEC+ members and set production ceilings for each country. Voluntary cuts are additional reductions committed to by a subset of members (typically the largest producers) beyond those quotas. The voluntary cuts made in 2023-2024 and unwound from April 2025 were the main swing variable for near-term supply until the 2026 war shut in Gulf output. Because voluntary cuts are not formally binding, compliance varies: Kazakhstan and Iraq have repeatedly exceeded their targets.
Saudi Arabia's pre-war dilemma (defend price and cede market share to US shale, or recover share and accept lower prices) has been deferred, not resolved. When Gulf flows normalize, a quota-free UAE, restored Saudi spare capacity, and the need to rebuild inventories will collide. How OPEC+ manages that return will decide whether 2027 looks like the EIA's $84 Brent or something closer to the pre-war $60s.
Non-OPEC Supply: A Buffer Too Small for the Shock
Before the war, the bear case rested on non-OPEC growth: non-OPEC+ producers added about 1.8 million barrels per day in 2025, and the IEA's January 2026 report projected 2026 supply growth of about 2.5 million barrels per day against demand growth of about 930,000. Those projects kept coming; they were simply too small to replace Gulf barrels.
- United States. The EIA has US crude output rising only from 13.7 million barrels per day in 2025 to 13.9 million in 2026 and 14.3 million in 2027, modest growth for $100 oil. The best Permian Basin inventory sits with a handful of operators after the 2024-2025 megadeal wave, public E&Ps prioritize shareholder returns over volume, and a backwardated strip means a well brought online today sells most of its oil at prices well below spot.
- Brazil, Guyana, and Argentina. New FPSOs at Petrobras's Buzios field and ExxonMobil's Stabroek Block (where the 250,000 barrel per day Uaru project is scheduled for 2026) keep adding low-breakeven pre-salt and deepwater barrels regardless of price, and Vaca Muerta shale adds 50,000 to 80,000 barrels per day a year.
Demand: From Slow Growth to Demand Destruction
Before the war, demand was the slow-moving half of the story: China's demand slowdown (EVs above half of new car sales, a property downturn cutting diesel use) had cut its incremental growth from well over 1 million barrels per day in 2023's post-lockdown rebound to under 0.5 million in 2025, while India, Southeast Asia, and Africa kept growing.
In 2026, price did the rationing. The IEA now expects world demand to fall by 2.6 million barrels per day to 102.4 million, a contraction driven by the Hormuz disruption and high prices, with only a partial 2 million barrel per day recovery in 2027. Diesel was the tightest product: US retail diesel averaged $6.29 per gallon in September, per the EIA. Demand destruction cuts both ways for a price deck. It caps how long prices can stay above $100, and part of it (fuel switching, efficiency gains, faster EV adoption) does not return when prices fall.
- 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 agencies like the EIA and IEA) reflect analyst judgment about supply-demand fundamentals. During a disruption like 2026's, the front of the curve can embed a risk premium that consensus forecasts discount, while the back of the curve already assumes normalization. Energy bankers typically use both: strip pricing for the first 2-3 years of NAV models and consensus for the long-term flat price assumption.
Natural Gas: Record LNG Exports, Softer Henry Hub
The Henry Hub natural gas market's 2026 story is the inverse of oil's: a global gas shock barely touched US prices, because US gas could not leave the country any faster.
- 2024 trough. Henry Hub averaged $2.21 per MMBtu, the lowest annual average in inflation-adjusted dollars the EIA has ever reported, on record production, a pause in new LNG export capacity, and a mild winter; Haynesville Shale producers operated near breakeven.
- 2025 recovery. Henry Hub rebounded about 60% to $3.53 as Plaquemines LNG and Corpus Christi Stage 3 ramped and US LNG exports rose to 15.1 Bcf/d from 11.9 Bcf/d, while producers held supply discipline.
- 2026 outcome. The EIA's October outlook has Henry Hub at $3.48 for 2026 and $3.16 for 2027, and the 2026 figure flatters the year: January averaged $7.72 after Winter Storm Fern, and February through December runs near $3.09 (EIA natural gas outlook). LNG exports set records (17.6 Bcf/d in 2026, 18.6 Bcf/d forecast for 2027), but production growth kept pace, leaving storage about 2% above its five-year average entering winter.
The reason a global shock left Henry Hub soft is export capacity. US terminals were already running near their limits, so higher European and Asian prices could not pull more US gas abroad; the only new terminal was Golden Pass, which shipped its first cargo on April 22. The shock showed up instead as a wider US-international spread, which the LNG market article covers in detail.
LNG Export Capacity: The Structural Demand Driver
US LNG export capacity is the most important medium-term driver for Henry Hub. Each new liquefaction train creates long-term demand for domestic gas, a structural floor under prices that did not exist before the US became a major exporter. The wave of projects coming online between 2024 and 2027 adds about 10-12 Bcf/d of capacity, nearly 80% above the 2023 baseline. Golden Pass LNG (QatarEnergy/ExxonMobil, 2.0 Bcf/d of nominal capacity across three trains) began exporting in April 2026, with Train 2 due in the second half of 2026 and Train 3 in the first half of 2027. The Gulf outage has strengthened the case for the long-term offtake contracts that underpin the next wave of FIDs, since buyers have now seen what concentrated supply can cost.
AI-Driven Power Demand: The Emerging Gas Catalyst
The second structural driver for gas demand is data center power consumption: data centers used 4.4% of US electricity in 2023 and could use 6.7-12% by 2028, according to a Lawrence Berkeley National Laboratory report for the DOE, with much of the new load met by gas-fired generation. Hyperscalers (Amazon, Microsoft, Google, Meta) are signing long-term power purchase agreements with gas generators, locking in demand for 10-15 years. That demand is price-inelastic: data centers need power whether gas costs $3 or $5 per MMBtu. It builds a medium-term floor rather than driving 2026 prices, which is why new load and record exports still left Henry Hub near $3.
Basis Differentials: Regional Dynamics
Regional basis differentials decide the realized price bankers model for E&P companies in each basin. The Waha basis (Permian gas relative to Henry Hub) often trades $1.00-2.00+ below Henry Hub because associated gas growth outruns takeaway capacity. Matterhorn Express, online since late 2024, gave temporary relief, but the discount narrows only as new pipelines arrive, and higher oil prices add pressure, since every extra Permian barrel brings gas with it.
The Dominion South basis (Appalachia) improved after the Mountain Valley Pipeline added about 2.0 Bcf/d of takeaway in mid-2024, though it remains negative. Gulf Coast basis premiums have strengthened as liquefaction demand concentrates near Sabine Pass, Cameron, and the Calcasieu/Plaquemines corridor, adding $0.10-0.30 per MMBtu for producers with access to those delivery points.
NGL Pricing: Mixed Signals Across the Barrel
NGL pricing in 2025-2026 is a mixed picture, with each component of the barrel following its own supply-demand dynamics. It matters for midstream and gas-weighted E&P valuations because NGLs often represent 15-25% of wellhead revenue for liquids-rich gas producers.
- Ethane. Recovery from gas processing averaged a record of about 3.1 million barrels per day in 2025 by EIA estimates, more than domestic crackers and export terminals can absorb. The surplus keeps prices depressed, though not low enough to trigger widespread ethane rejection (leaving ethane in the gas stream rather than extracting it).
- Propane. US propane exports grew about 9% in 2025 on Asian demand. In 2026, the new Middle Eastern supply expected to pressure global prices was instead trapped behind Hormuz: Argus estimates the closure removed more than 7 million tonnes of LPG, about 5% of global seaborne supply, and US Gulf Coast exports hit record highs to fill the gap. Like Henry Hub, US propane stayed tied to domestic balances: the EIA has Mont Belvieu propane averaging about $0.74 per gallon in 2026, almost unchanged from $0.75 in 2025. Its petrochemical (PDH) and heating uses make propane the most seasonally volatile NGL.
- Butane and natural gasoline. These heavier components track crude more closely because refiners use them as blending components, so elevated crude through 2026 strengthened their prices, benefiting NGL-weighted processors and fractionators at Mont Belvieu.
How the 2026 Price Environment Affects Energy Banking
The link between commodity prices and deal flow is not linear, and in 2026 the volatility of prices and the shape of the curve mattered more than the level itself.
| Commodity | 2025 Average | 2026 (EIA, October) | 2027 (EIA) | Impact on Banking |
|---|---|---|---|---|
| Brent crude | $69/bbl | $96/bbl (Q4: $105) | $84/bbl | Bid-ask gaps slow upstream M&A |
| WTI crude | $65/bbl | $88/bbl (Q4: $97) | $80/bbl | NAV models hinge on the deck used |
| Henry Hub gas | $3.53/MMBtu | $3.48/MMBtu | $3.16/MMBtu | Gas M&A muted; Haynesville assets scarce |
| Propane (Mont Belvieu) | $0.75/gal | $0.74/gal | $0.69/gal | Record exports; midstream G&P margins stable |
Upstream M&A: The Price Sensitivity Matrix
US upstream M&A totaled $65 billion in 2025, with $23.5 billion in Q4 alone, Enverus reported. The war stalled that momentum: Enverus counted only $9.1 billion in the second quarter of 2026, down 76% from the first quarter, and blamed volatility tied to the Iran conflict for widening bid-ask spreads rather than for weaker buyer interest. Sellers point to spot cash flows; buyers, who will own the asset after flows normalize, price the strip and their own lower decks. Contingent payments linked to prices and hedges transferred with the asset are the usual bridges.
The old rule of thumb still holds in modified form: below $55 WTI, upstream M&A freezes and restructuring rises; at $65-75, mid-cap consolidation proceeds; above $85, deals usually accelerate. 2026 added a caveat: above $85 on a steeply backwardated curve, buyers have the cash but will not pay for spot. Enverus expects activity to strengthen in the second half of 2026 as higher prices lift buyers' free cash flow.
Midstream and Power: Less Price-Sensitive but Still Affected
For midstream, record LNG exports drive long-haul pipeline and LNG infrastructure investment, and midstream EBITDA growth of 5-10% a year is expected for most major operators through 2027. Fee-based contract structures insulate operators from direct price exposure, but throughput still tracks upstream activity.
For power, surging AI-driven demand supports merchant generators and nuclear operators even with gas prices subdued. The Constellation/Calpine merger shows the value the market places on dispatchable generation, and because gas sets the marginal clearing price, zero-fuel-cost nuclear and renewables earn wider margins whenever gas rises.
International Dimensions
Outside the US, the shock widened regional price gaps. In the first days of the war, Dutch TTF gas futures more than doubled to about €65/MWh, a level last seen at the end of the 2022-2023 energy crisis, while Henry Hub did not follow. That trans-Atlantic spread underpins the bull case for US LNG export projects and the cross-border supply mandates around them.
Gulf producers face the opposite of a windfall: high prices but stranded volumes. For them, export routes matter more than fiscal breakevens, which is why bypass pipelines (including new UAE capacity the EIA expects in 2027) and ship-to-ship transfers along Oman's coast have become central to Gulf export plans.
