Introduction
On February 27, 2026, Brent crude settled a little above $71 a barrel in a market most forecasters expected to be oversupplied for the rest of the year. The next day, US and Israeli strikes on Iran started a war that Iran answered by attacking ships and Gulf energy facilities, and within days the Strait of Hormuz, the channel that carries about a fifth of the world's oil and liquefied natural gas, was effectively closed. What followed is, in the assessment of Commodity Context founder Rory Johnston, the largest oil supply shock in the history of the market.
This article tells the story of the crisis once, so that the rest of the section can build on it: why the strait matters, how the disruption unfolded from February to October, what it did to LNG, how governments and producers responded, and what it changes in the day-to-day work of an energy banker. Prices and forecasts sit in the commodity price environment, the structural actors in global energy geopolitics and gas markets in the LNG market article.
Why the Strait of Hormuz Matters to Energy Markets
The strait is a narrow passage between Iran and Oman that connects the Persian Gulf to the Gulf of Oman and the Arabian Sea. Almost everything the Gulf producers export by sea has to pass through it. According to the EIA's analysis of the Hormuz chokepoint, oil flows through the strait averaged 20 million barrels per day in 2024, equal to roughly 20% of global petroleum liquids consumption and more than a quarter of all seaborne oil trade. About one-fifth of global LNG trade also moved through it, almost all of it from Qatar.
The geography of demand matters as much as the volume. The EIA estimates that 84% of the crude and 83% of the LNG moving through Hormuz in 2024 went to Asia, with China, India, Japan and South Korea taking the largest shares. The United States, by contrast, imported only about 0.5 million barrels per day through the strait. That demand asymmetry shaped the whole crisis: the physical shortage landed in Asia and Europe, while US producers and exporters sat on the other side of the trade.
- Oil Chokepoint
A narrow shipping channel on a major trade route through which a large share of the world's oil or LNG must pass, so that even a temporary blockage delays supply, raises freight and insurance costs and lifts global prices. The Strait of Hormuz is the most important chokepoint because most of the volume crossing it has no practical alternative route; the Strait of Malacca, the Suez Canal and the Bab el-Mandeb are the others energy analysts track most closely.
The Limited Bypass Routes
Only two pipeline systems let Gulf producers avoid the strait, and neither was built for a full closure:
- Saudi Arabia's East-West pipeline runs from the Abqaiq processing center to the Red Sea port of Yanbu. Its nameplate capacity is 5 million barrels per day, temporarily raised to 7 million in 2019 by converting gas liquids lines to crude.
- The UAE's pipeline to Fujairah, a 1.8 million barrel per day line that delivers crude to the Gulf of Oman, outside the strait.
- Iran's Goreh-Jask pipeline to the Gulf of Oman has an effective capacity of only around 300,000 barrels per day and had stopped loading cargoes in late 2024.
Before the war, the EIA estimated that only about 2.6 million barrels per day of unused Saudi and UAE pipeline capacity could be switched on in a disruption. Qatar's LNG has no bypass at all: Ras Laffan has no export terminal outside the Gulf. That is why the market treated Hormuz as a binary risk for decades, and why the 2026 closure removed far more supply than any spare capacity or stock release could replace.
How the Crisis Unfolded: February to October 2026
The crisis came in three phases: the initial closure and spike, a spring of ceasefires that never fully reopened the strait, and a second shock from late summer when the diplomatic track collapsed. The table tracks the physical Brent spot price from the EIA's daily Brent series, which ran well above front-month futures for most of the year because physical barrels were scarce right now.
| Date | Event | Brent spot (per barrel) |
|---|---|---|
| Feb 27 | Last close before the war | $71.32 |
| Mar 12 | Brent crosses $100 after IEA release fails to calm market | $102.38 |
| Apr 7 | Peak ahead of two-week ceasefire | $138.21 |
| Apr 17 | Iran declares strait open, then reimposes control | $98.63 |
| Jul 2 | War-time low after the June memorandum of understanding | $68.53 |
| Sep 15 | Attacks halt Saudi East-West pipeline | $130.80 |
| Oct 14 | Worst wave of tanker attacks of the war | $126.55 |
The Closure and the First Spike
When markets opened after the February 28 strikes, Iran had begun attacking tankers and energy facilities across the Gulf, and production from Qatar to Iraq ground down as storage filled and exports stopped. The International Energy Agency responded on March 11 with the largest emergency stock release in its history, 400 million barrels, more than double the 182.7 million barrels released after Russia invaded Ukraine in 2022. At that point the IEA estimated Gulf exports of crude and products at less than 10% of pre-war levels, and Brent went through $100 the next day anyway. A week later, after Israel struck Iran's South Pars gas field, Iran hit Qatar's Ras Laffan complex, turning an oil crisis into a gas crisis as well.
Ceasefire, Blockade and the False Reopening
Spot Brent peaked at $138.21 on April 7, just before a two-week ceasefire brokered by Pakistan was announced, and fell more than 10% the next day. The truce did not reopen the strait. The US Navy imposed a blockade on Iranian ports after talks in Islamabad failed, Iran's foreign minister declared the strait open on April 17 (prices dropped more than 10% that day) and Iranian forces reimposed control within hours. On April 28 the UAE, after six decades of membership, announced that it would leave OPEC and OPEC+ from May 1, citing a review of its production policy and capacity. Shut-in Gulf crude production peaked at 10.9 million barrels per day in May, according to the EIA.
The low point for prices came after the US and Iran agreed a memorandum of understanding on June 17, under which Iran was expected to end the closure in exchange for the lifting of the blockade while the two sides negotiated a nuclear deal within 60 days. The market front-ran a full reopening, and spot Brent fell to $68.53 on July 2, below where it started the war.
The Second Shock
The memorandum unravelled in July as Iran attacked tankers moving along Oman's coast under US protection, and it expired on August 17 with neither side willing to extend it; Brent futures settled at $90.87 that day, with only a handful of ships crossing the strait against about 130 a day before the war. In September, attacks on Saudi Arabia's East-West pipeline temporarily halted the main bypass route, which the EIA estimates had been carrying more than 5 million barrels per day to Yanbu, and spot Brent reached $130.80 on September 15.
Flows then recovered for a few weeks: with a US-assisted convoy system and ship-to-ship transfers along Oman's coast, crude shipments through the strait briefly touched pre-war levels in late September. Iran answered with the worst spate of attacks of the war: ten tankers struck between September 28 and October 4 and fifteen more incidents logged by UKMTO by October 14. By mid-October, Kpler data put crude exports through Hormuz at 9.4 million barrels per day, about 70% of the pre-war average, and Brent futures closed at $109.86 on October 16, with WTI at $101.41.
The LNG Shock: Ras Laffan and Qatar's Force Majeure
For gas markets, the strikes on Ras Laffan mattered more than the closure itself. QatarEnergy's chief executive, Saad al-Kaabi, said the attacks damaged two of Qatar's 14 LNG trains (S4 and S6, in which ExxonMobil is a partner) and one of its two gas-to-liquids plants, sidelining 12.8 million tons per year, about 17% of Qatar's LNG export capacity, for three to five years. He put the lost revenue at about $20 billion a year and the replacement cost of the damaged units at about $26 billion.
- Force Majeure
A contract clause that excuses a party from performing its obligations when an extraordinary event outside its control, such as war, makes performance impossible. In LNG, a seller declaring force majeure stops delivering contracted cargoes without paying the penalties it would normally owe, which leaves buyers to replace the volumes at spot prices. QatarEnergy declared force majeure on its entire output after the first attacks, then on long-term contracts tied to the two damaged trains.
QatarEnergy has extended its force majeure month by month, with some buyers in Pakistan, Bangladesh and Italy told that cancellations would run into November and early December, and European and Asian gas prices climbed to their highest levels since late 2022. With roughly 20% of global LNG supply affected, the "coming LNG glut" that dominated 2025 forecasts turned into a scramble for flexible cargoes.
The other side of that trade was the United States. US LNG exports, about 15 billion cubic feet per day in 2025, average roughly 18 in 2026 in the EIA's October outlook, helped by Golden Pass LNG, a QatarEnergy and ExxonMobil joint venture in Texas that shipped its first cargo on April 22, while Henry Hub stays near $3.50 per million Btu because US gas production kept growing. A widening gap between US and international gas prices is the best possible backdrop for signing long-term offtake contracts, which is why the crisis strengthened rather than weakened the pipeline of US export projects.
The Supply Response: Stocks, Workarounds and OPEC
Every lever the market had was pulled, and none was large enough. Governments released stocks: the IEA's 400 million barrels in March, then further US Strategic Petroleum Reserve exchanges of 40 million barrels announced on September 29 and a G7 package on October 2. Gulf producers shipped what they could through bypass pipelines, overland routes and ship-to-ship transfers off Oman. Buyers cut back: China, the largest importer, reduced crude imports by about 4 million barrels per day, a cut Rapidan Energy's Bob McNally credits with keeping prices from surging even higher.
The EIA's estimates of shut-in production show how slowly the physical gap closed:
- Peak disruption: shut-ins averaged about 8.5 million barrels per day from March to July and peaked at 10.9 million in May, with Saudi Arabia, Iraq and Kuwait the largest losers.
- Partial recovery: shut-ins fell to 5.8 million barrels per day in August and 4.8 million in September as workarounds expanded.
- The forecast: the EIA expects shut-ins to average about 4.5 million barrels per day in the fourth quarter of 2026 and most regional production to return to pre-war levels by the end of the second quarter of 2027, helped by new UAE bypass pipeline capacity due in 2027.
The supply response from outside the Gulf was strikingly muted. The EIA has US crude production rising only from 13.7 million barrels per day in 2025 to 13.9 million in 2026 and 14.3 million in 2027, despite three-digit prices for much of the year. The reasons are the shape of the curve and capital discipline: shale wells take months to bring online, and producers deciding whether to add rigs looked at 2027 prices, not spot. OPEC+ itself had little to offer, because its spare capacity sits mostly in Saudi Arabia and the UAE, behind the same strait. The full story of OPEC's role is in our article on OPEC and OPEC+ market impact.
What the Shock Means for Energy Banking
For bankers, the crisis was less about the headline price than about how far apart spot prices and the long-dated curve became. Three problems dominated the year's work.
Price Decks and the Strip-Versus-Spot Gap
The war pushed the oil market into extreme backwardation, where prompt barrels trade far above later delivery months. In mid-October, physical Brent in the EIA series sat in the mid-$120s, front-month futures near $110, and the EIA's own forecast for 2027 averaged $84, falling to $74 by the fourth quarter of 2027. An upstream valuation now depends almost entirely on which of those numbers the model uses, which is why understanding forward curves and backwardation and the standard price-deck scenarios became core interview knowledge rather than a technical detail.
Lenders faced the same choice. Reserve-based lenders size borrowing bases on conservative bank price decks that typically sit below the strip, so a spot spike raises availability at the semiannual borrowing base redetermination far less than headline prices suggest, and a steeply backwardated strip limits the uplift further.
Hedging and the Upstream Bid-Ask Problem
Backwardation also opened a gap between buyers and sellers of oil assets. Sellers anchored on spot cash flows; buyers, who would own the asset after prices normalize, priced the strip and their own lower decks. The result showed up in deal volume: Enverus counted only $9.1 billion of US upstream M&A in the second quarter of 2026, down 76% from a first quarter inflated by Devon's merger with Coterra, and blamed volatility tied to the Iran conflict for widening bid-ask spreads. Enverus described the gap as a negotiation obstacle rather than weak demand, and the tools for closing it are familiar ones: hedges transferred with the asset, price-linked contingent payments, and structures that let the buyer pay for strip value up front and share upside if spot holds. The hedging toolkit became deal structuring, not just risk management.
Winners, Losers and Where the Mandates Are
The shock redistributed value across the energy chain in ways that drive banking activity well beyond upstream:
- US exporters and producers gained the most: record LNG export volumes, wide international spreads that support new LNG contracting and project financing, and oil producers generating cash they can use for buybacks, debt reduction or acquisitions once the bid-ask gap narrows.
- Refiners and fuel markets saw extreme product tightness: US retail diesel averaged $6.29 a gallon in September in the EIA's outlook, which supported crack spreads for refiners with secure crude supply and squeezed those without.
- Shipping and insurance repriced: tanker rates hit records in September as war-risk premiums rose and ships took longer routes.
- Importers and Gulf producers bore the cost: Asian and European buyers paid spot prices for replacement cargoes, while Gulf national oil companies face years of repair and new investment in bypass routes and storage outside the strait.
The broader legacy of the crisis is a change in how the industry prices risk. For a decade, the market treated a Hormuz closure as a tail event that spare capacity and strategic stocks could absorb; 2026 showed that neither works when the barrels and the spare capacity sit behind the same strait. That lesson will shape energy security spending, Gulf infrastructure, US export investment and the risk premium in long-dated prices for years after the strait fully reopens.
