Why Oil Prices Stayed Below $150 During the U.S.-Iran War

The effective closure of the Strait of Hormuz should, according to the conventional oil-market playbook, have produced a historic price shock. Before the U.S.-Israeli war with Iran began on February 28, 2026, roughly one-fifth of the world’s oil supply passed through the narrow waterway connecting the Persian Gulf with the Arabian Sea. Analysts openly discussed Brent crude at $150 a barrel, while some estimates extended to $200.

That did not happen. Brent futures reached approximately $126 a barrel—well above pre-war levels but still below the record of almost $147 set in 2008. From the start of the war through June 11, Brent averaged about $101. It then briefly fell below $70 in early July after a temporary agreement reopened the strait, rose above $100 when fighting and shipping disruptions intensified again, and settled at $88.36 on July 27 after the United States paused a renewed air campaign. At 6:10 a.m. GMT on July 28, Brent was trading near $87.86 and West Texas Intermediate near $82.24. :contentReference[oaicite:0]{index=0}

The reason oil prices stayed below $150 was not that the Strait of Hormuz proved unimportant. The disruption was immense. Instead, the world responded more quickly—and consumed less oil—than most pre-war forecasts assumed. China sharply reduced crude imports and fuel exports. Its enormous electric-vehicle fleet gave households and businesses alternatives to gasoline and diesel. The United States increased oil production to a record level. International Energy Agency members released emergency reserves. Saudi Arabia redirected crude toward the Red Sea. Traders became wary of betting aggressively on higher prices because diplomatic announcements repeatedly caused violent reversals.

Together, those responses turned what might once have been a straightforward scarcity shock into a contest between lost Gulf supply and rapid adaptation elsewhere. The market never became comfortable. It became unusually volatile, politically sensitive and difficult to trade. Yet it did not run out of oil in the way the most extreme forecasts implied.

Last updated: July 28, 2026, 9:30 a.m. CEST. Market prices cited in this article include their individual observation times.

Key Takeaways

• Brent stayed below $150: The international benchmark peaked around $126 during the first five months of the conflict, despite forecasts that a prolonged Hormuz closure could push crude toward $150 or even $200.
• China absorbed much of the shock: Chinese crude imports fell to 7.12 million barrels per day in June, their lowest level since October 2016 and roughly 41% below the year-earlier level.
• Demand fell as well as supply: China restricted fuel exports, reduced refinery runs and leaned more heavily on electric taxis, electric cars, electric trucks, rail and mass transit.
• Emergency reserves mattered: The IEA’s 32 member countries approved a 400 million-barrel release, including 172 million barrels authorized from the U.S. Strategic Petroleum Reserve.
• U.S. production provided an additional buffer: American crude output reached a record 13.93 million barrels per day in April.
• Saudi Arabia bypassed part of the closure: Exports from Yanbu on the Red Sea approached 4 million barrels per day in March as crude was redirected through the East-West Pipeline.
• Prices remained headline-driven: Repeated ceasefire claims, renewed strikes and conflicting descriptions of the Hormuz agreement discouraged traders from holding large, persistent bullish positions.
• The risk has not disappeared: Physical flows through Hormuz remained severely depressed in late July, and disruption spread toward the Red Sea and Saudi export infrastructure.

Why Oil Prices Stayed Below $150

Oil prices stayed below $150 because the supply loss was partly offset by lower consumption, emergency stock releases, rising production outside the Persian Gulf and limited export routes that bypassed the Strait of Hormuz. The market also anticipated that at least some of the missing barrels would eventually return.

That distinction is important. A disruption does not determine the price by itself. The price depends on how much supply is lost, how much oil can be released from storage, how quickly producers elsewhere can raise output, how much demand consumers are willing or able to eliminate and how long traders expect the imbalance to last.

Before the war, the most alarming scenarios often treated the approximately 20 million barrels per day of crude oil, condensate and petroleum products moving through Hormuz as if it might disappear from the global market while everything else remained unchanged. That was a useful stress test, but it was not a complete forecast.

Consumers changed behavior. Refiners cut operations. Governments released inventories. Saudi Arabia shifted exports westward. The United States produced more crude. Atlantic Basin suppliers increased shipments. High prices weakened demand in countries that had depended heavily on Gulf imports. The physical system bent under extraordinary pressure, but it did not remain static.

The result was still painful. According to the U.S. Energy Information Administration, an estimated 11.2 million barrels per day of Middle Eastern production was shut in at the peak in May. Global inventories fell by an estimated average of 5.1 million barrels per day during the second quarter. Those figures describe a severe shortage, not a trivial interruption. Yet the size of the inventory draw also shows why oil stored before the war mattered so much. Supply and consumption could diverge temporarily because inventories filled the gap. :contentReference[oaicite:1]{index=1}

Oil traders were therefore pricing several realities at once: a present shortage, a large emergency response, weaker demand, the possibility of renewed tanker traffic and the risk of another escalation. Those forces did not cancel one another neatly. They produced repeated rallies and collapses instead of an uninterrupted march toward $150.

The Argument That Framed the Oil-Market Debate

Reuters Energy Editor Dmitry Zhdannikov summarized the central puzzle in a July video analysis: a partial or complete Hormuz closure had long been treated as a scenario in which oil might quickly reach $150 or $200, yet the market had not produced that outcome. He emphasized China’s rapid reduction in imports, reduced fuel exports, the use of electric transportation, rising U.S. production, strategic-stock releases, Saudi rerouting and reduced speculative liquidity. :contentReference[oaicite:2]{index=2}

The broad argument is supported by subsequent data, although several details require careful interpretation. China did not suddenly replace five million barrels per day of oil consumption with electric vehicles. The decline from normal import levels to 7.12 million barrels per day reflected several overlapping forces: lower end-user demand, refinery reductions, restrictions on refined-product exports, use of inventories accumulated earlier and the physical difficulty of obtaining customary Gulf supplies.

Electric transportation nevertheless made the adjustment far easier. A country dominated by gasoline cars, diesel trucks and limited public transport would have experienced a more rigid demand response. China entered the crisis with the world’s largest electric-vehicle fleet, heavily electrified urban taxi networks, extensive high-speed rail, large subway systems and growing use of electric trucks. Those investments created options that could be used more intensively when petroleum became expensive.

The transcript’s reference to China buying “50%” is best understood as the country’s exposure to Middle Eastern and Hormuz-linked imports, not as China consuming half the world’s oil. Columbia University’s Center on Global Energy Policy calculated that China officially imported 42% of its crude—about 4.9 million barrels per day—from Saudi Arabia, Iraq, the United Arab Emirates, Oman, Kuwait and Qatar in 2025. Tanker data also indicated substantial Iranian imports that were not recorded by Chinese customs as Iranian-origin oil. Approximately 45% to 50% of Chinese crude imports normally transited Hormuz. :contentReference[oaicite:3]{index=3}

The central conclusion therefore survives closer examination: the market underestimated China’s capacity to reduce imports and petroleum use during a crisis. But that capacity came from a combination of technology, policy, inventories, economic weakness and administrative controls. It should not be attributed to one cause.

A Timeline of the 2026 Oil Shock

January and February: Risk Premiums Build

Brent began 2026 near $61 a barrel and climbed toward $72 as the probability of conflict increased. That rise represented a risk premium rather than an actual shortage. Traders were paying more because they believed future Gulf supply might be interrupted.

The distinction between a risk premium and a physical shortage became visible after February 28. U.S. and Israeli military action against Iran was followed by attacks on shipping and a de facto closure of Hormuz. Tankers faced the risk of physical damage, insurance became more expensive or unavailable, and Gulf producers reduced output because crude could not leave through normal channels.

March: The First Major Price Surge

Brent crossed $100 on March 12 and continued rising during the month. The widening gap between Brent and U.S. West Texas Intermediate reflected geography. Brent is the more internationally exposed benchmark, while WTI benefited from strong U.S. inventories, domestic production and expectations that Washington would release oil from the Strategic Petroleum Reserve.

On March 11, all 32 IEA member countries approved the largest coordinated emergency-stock release in the agency’s history: 400 million barrels of oil and refined products. The United States authorized 172 million barrels from the SPR, scheduled for delivery over approximately 120 days. :contentReference[oaicite:4]{index=4}

Saudi Arabia simultaneously accelerated use of its East-West Pipeline. By the week ending March 22, crude exports from Yanbu on the Red Sea had risen to nearly 4 million barrels per day. The pipeline could move as much as 7 million barrels per day westward, although part of that capacity was needed by domestic refineries and not all of it was immediately available for export.

April and May: Supply Losses Peak, Demand Begins to Break

The disruption deepened during the spring. EIA estimates indicate that production shut-ins across Saudi Arabia, Iraq, Kuwait, the UAE, Iran, Qatar and Bahrain reached approximately 10.4 million barrels per day in April and 11.2 million in May.

Yet April also brought a record in U.S. production. American output rose by 216,000 barrels per day from March to 13.93 million barrels per day. New Mexico produced a record 2.37 million barrels per day, while Texas reached 5.83 million. The Permian Basin remained responsible for roughly half of U.S. crude output. :contentReference[oaicite:5]{index=5}

Demand indicators weakened sharply. Chinese gasoline and diesel use fell. Refinery utilization declined. Travel shifted toward rail, subways, electric taxis and electric or hybrid vehicles. The International Energy Agency revised its global demand outlook downward as high prices and physical scarcity spread through Asia and the Middle East.

June: A Temporary Agreement Reopens the Strait

Washington and Tehran reached an interim memorandum in June. Reuters reported that the framework called for a cessation of military operations, commercial passage through Hormuz during a 60-day negotiation period and eventual lifting of the U.S. naval blockade. Difficult questions—including the Iranian nuclear program and the precise authority governing Hormuz traffic—were deferred. :contentReference[oaicite:6]{index=6}

Tanker activity increased after the agreement, and Brent averaged $85 in June, $22 below its May average. It fell below $70 on July 1, close to its level when the war began. The rapid decline demonstrated how much of the spring price reflected expectations of prolonged closure rather than a permanent loss of resources.

July: The Agreement Frays

The two sides disputed the meaning of the Hormuz provisions. Washington argued that the agreement required free passage. Tehran maintained that it retained supervisory authority and could direct ships through a channel closer to the Iranian coast. Hostilities resumed, the United States restored a blockade against Iranian ports, and ship traffic again fell sharply.

Only nine vessels crossed the strait on July 15, according to Kpler data cited by Reuters. No very large crude carrier or LNG tanker was visibly transiting that day. Oil rose back above $100 as the conflict expanded toward the Red Sea and threatened the Saudi alternative route.

July 26–28: Another Pause, Another Price Reversal

President Donald Trump suspended a renewed U.S. bombing campaign over the weekend of July 25–26, saying the United States was engaged in talks and could resume strikes if diplomacy failed. Iran disputed the suggestion that it had requested negotiations but said messages continued through intermediaries.

Brent fell $8.42, or 8.7%, on July 27 to settle at $88.36. WTI lost $6.70, or 7.5%, to $82.61. The decline occurred even though fewer than 10 commodity vessels per day had crossed Hormuz during the weekend. In other words, the futures market reacted to the possibility of improving supply before meaningful physical normalization had occurred.

On July 28, Oman was reported to have proposed a regional management mechanism for Hormuz, modeled partly on cooperation in the Strait of Malacca. Iran would not exercise sole control under the proposal, and users could make voluntary contributions toward navigation, environmental protection and search-and-rescue services. The proposal had not become a binding agreement by the research cutoff. :contentReference[oaicite:7]{index=7}

How Important Is the Strait of Hormuz?

The Strait of Hormuz is not merely one shipping route among many. It is the principal maritime exit for oil produced in Saudi Arabia, the United Arab Emirates, Iraq, Kuwait, Qatar, Bahrain and Iran. Its importance comes from the combination of enormous volume, limited alternatives and the concentration of the world’s spare production capacity inside the Persian Gulf.

International Energy Agency data show that nearly 15 million barrels per day of crude oil and condensate passed through Hormuz in 2025, equal to approximately 34% of internationally traded crude. A further 4.9 million barrels per day of refined products moved through the strait. Total oil flows were just under 20 million barrels per day.

About 80% of those barrels were destined for Asia. China, India and Japan were the largest importers. China and India together received 44% of the crude passing through the waterway. Japan and South Korea were especially exposed because their economies rely heavily on imported energy and have limited domestic crude production.

Hormuz is also critical to natural gas. Approximately 93% of Qatar’s LNG exports and 96% of the UAE’s LNG exports normally transit the strait. Combined, those flows represented about 19% of global LNG trade before the war. An oil analysis that ignores LNG therefore understates the economic significance of the route. Gas shortages can raise electricity, fertilizer and industrial costs even when crude prices remain below their theoretical maximum. :contentReference[oaicite:8]{index=8}

The waterway’s strategic importance is amplified by spare capacity. Saudi Arabia holds much of the world’s ability to raise production quickly. If Saudi crude cannot leave the region, that spare capacity is less useful. A conventional supply shock can sometimes be offset by asking OPEC’s largest producer to pump more. A Hormuz closure interferes with both existing exports and the principal source of emergency additional production.

Yet “20 million barrels per day passes through Hormuz” does not mean a closure permanently removes 20 million barrels per day from consumption. Some oil can be redirected through pipelines. Some cargoes can move through protected convoys or unconventional transfer arrangements. Gulf producers can draw from tanks outside the strait. Importers can use their own reserves. Refineries can process alternative grades. Consumers can reduce demand.

Those adjustments are expensive and incomplete, but they explain why the gross flow through the chokepoint is larger than the eventual net shortage faced by the world economy.

Why the $150 and $200 Forecasts Were Plausible

The forecasts were not irrational. Oil demand is usually inelastic over short periods, meaning consumers cannot immediately reduce consumption when prices rise. A commuter still has to reach work. A delivery company still has contracts to fulfill. An airline cannot rapidly convert its fleet to another fuel. A petrochemical plant designed around a particular feedstock cannot instantly redesign its process.

If ten or fifteen million barrels per day disappeared while demand remained unchanged, buyers would have to bid aggressively for the remaining supply. The price would rise until enough consumption was destroyed, additional supply appeared or inventories were released. Because the oil market normally balances within a relatively narrow margin, a loss representing even 2% or 3% of global demand can cause a disproportionate move.

The $150 estimates also had historical precedent. Brent approached $147 in 2008 without a Hormuz closure of comparable duration. Adjusted for inflation, that record would be considerably higher in 2026 dollars. A nominal price above $150 was therefore not beyond the range of history.

A $200 scenario generally required harsher assumptions: a near-total and prolonged closure, damage to oil infrastructure, limited strategic releases, slow demand response, constrained non-Gulf production and little confidence in diplomacy. Some forecasts were intended as tail-risk scenarios rather than base cases, but that distinction was often lost when the largest number became the headline.

The central mistake was not necessarily the estimate of how disruptive Hormuz could be. It was underestimating the elasticity that technology, government intervention and stored oil had introduced into the system. China’s consumers had more alternatives than analysts assumed. Governments were willing to release unprecedented volumes from reserves. The Saudi pipeline system handled more crude than in normal conditions. U.S. shale responded to higher prices. The market also repeatedly priced a chance that the closure would end.

A forecast can be internally sound and still fail because one assumption changes. In this case, several assumptions changed at once.

China Became the World’s Swing Consumer

Saudi Arabia has traditionally been called the oil market’s swing producer because it can raise or lower output to influence global balances. During the 2026 crisis, China played an analogous role on the demand side.

China is the world’s largest crude importer and the largest single destination for Gulf oil. Before the war, it imported approximately 11 million to 12 million barrels per day, depending on the month and measurement method. Its refineries supplied domestic transport and industry while also exporting gasoline, diesel and jet fuel into regional markets.

By June, official Chinese crude imports had fallen to 29.27 million metric tons, equivalent to 7.12 million barrels per day. That was a 41.3% year-over-year decline and the lowest monthly volume since October 2016. Seaborne imports were estimated at approximately 6 million barrels per day. Middle Eastern supplies reached a ten-year low, while tanker tracking indicated Iranian deliveries below 800,000 barrels per day. :contentReference[oaicite:9]{index=9}

A decline of roughly five million barrels per day from common pre-war import levels is equal to around 5% of world oil consumption. It is difficult to overstate the importance of that adjustment. Had China attempted to replace every missing Gulf barrel immediately, it would have competed with Japan, South Korea, India, Europe and other importers for Atlantic Basin crude. Prices, freight rates and refining margins would probably have risen much further.

Instead, China drew on several buffers. It had accumulated large inventories before the war. Estimates cited by Columbia University’s Center on Global Energy Policy suggested 1.39 billion barrels in storage at the beginning of March, equivalent to approximately 120 days of 2025 net crude imports. The exact amount and accessibility of Chinese strategic and commercial stocks are not as transparent as U.S. reserve data, but the country had clearly built substantial capacity.

China also curtailed refined-fuel exports. That decision reduced the amount of crude its refineries needed to process. It effectively told regional customers that domestic security took priority over serving the export market.

Refinery utilization fell to 57.72% in June, according to Oilchem data reported by Reuters. That was 3.28 percentage points below May and 13.09 percentage points below the year-earlier level. China’s official crude-processing volume was already down 9.1% year over year in May, according to the National Bureau of Statistics.

The petrochemical sector contributed to the decline. Years of capacity expansion had weakened margins for products such as plastics and chemicals. Lower construction activity, a prolonged property downturn and subdued industrial demand reduced the incentive to run refineries simply because capacity existed.

Diesel consumption was particularly exposed to China’s economic structure. Construction, mining, freight and heavy industry are large diesel users. When local infrastructure projects were postponed, property activity weakened and some truck operators shifted to electricity or LNG, diesel demand fell without requiring a collapse in personal mobility.

This is why China’s response cannot be described purely as conservation. Part of the decline was cyclical weakness. Part was policy. Part came from inventories. Part reflected structural electrification. The combination allowed the country to import far less crude than the oil market had expected.

Could China Maintain Such Low Imports?

Probably not indefinitely at the June level. Inventories are finite. Refiners cannot permanently avoid maintenance, domestic demand or contractual obligations. Some industrial and petrochemical uses of oil have few immediate substitutes. Beijing began easing fuel-export restrictions in July after the temporary U.S.-Iran agreement, allowing refiners to plan roughly 3 million metric tons of gasoline, diesel and jet-fuel exports.

A normalization of Chinese refinery runs would raise crude demand. That possibility remains one of the clearest upside risks for oil. China does not need to return fully to pre-war imports to tighten the market; an increase of one or two million barrels per day would be material while Hormuz traffic remains depressed.

Still, the crisis revealed that China’s minimum practical oil requirement was lower than many analysts had believed. That discovery may influence long-term forecasts even after the war ends.

Electric Vehicles Turned Energy Policy Into an Emergency Buffer

Electric vehicles did not solve the Hormuz crisis, but they changed the speed and scale of China’s demand response. Investments made over more than a decade suddenly functioned as energy-security infrastructure.

Electric cars accounted for nearly 55% of Chinese new-car sales in 2025, according to the IEA. China’s automakers supplied 60% of electric cars sold globally, and the country operated the world’s largest EV fleet. Electric vehicles already displaced approximately one million barrels per day of Chinese oil demand in 2025. The IEA projects that displacement could reach 2.7 million barrels per day by 2030. :contentReference[oaicite:10]{index=10}

Those numbers represent avoided consumption relative to a world in which the same travel occurred in internal-combustion vehicles. They do not imply that China’s recorded oil demand fell by one million barrels per day in a single year. The fleet accumulated gradually. Its importance during the war was that millions of journeys could continue without gasoline.

Urban taxis illustrate the mechanism. Roughly half of China’s taxis were electric by mid-2026, with penetration approaching 100% in several large cities. Taxi and ride-hailing trips increased after the war began even as petroleum use fell. In May, passengers took approximately 3.05 billion trips, 6% more than in the comparable post-February period of 2025. :contentReference[oaicite:11]{index=11}

High gasoline prices did not necessarily force people to stay home. Some switched from personal cars to cheaper electric taxis. Others used subways or high-speed rail. Charging activity rose sharply. More highway travel took place in electric or hybrid vehicles. That is a different form of demand destruction from a recession or lockdown: mobility can remain relatively strong while petroleum consumption weakens.

Electric trucks also mattered. China accounted for most of the increase in global electric-truck sales in 2025, when one in four trucks sold in the country was electric. Battery-powered trucks are particularly competitive on predictable routes where vehicles can recharge at depots and where high utilization makes fuel savings more valuable.

Diesel trucks have historically been one of the hardest parts of transport to electrify. Their emergence in China means oil demand is no longer protected simply because freight activity continues. An electric truck can carry goods without consuming diesel, while an LNG truck can reduce diesel use even if it remains dependent on another fossil fuel.

China’s electricity system absorbed the shift more easily than an oil-import system could absorb lost Gulf cargoes. The country has abundant domestic coal, rapidly expanding renewable generation, nuclear power, hydropower and an enormous transmission network. Electrification diversified the energy source behind transportation.

That does not make the transition costless. Higher charging demand places pressure on grids. Coal-fired generation can rise when electricity consumption accelerates. Battery production depends on minerals and industrial supply chains. Electric vehicles also require substantial upfront investment.

From an oil-security perspective, however, the crucial point is flexibility. Electricity can be produced from many domestic sources. Gasoline and diesel are refined almost entirely from crude oil. When maritime crude supply is interrupted, an electric fleet provides a degree of substitution that a conventional vehicle fleet cannot.

The Crisis May Accelerate a Structural Shift

High fuel prices improve the operating-cost advantage of electric vehicles. The IEA estimated that, using April 2026 retail energy prices and home charging, the savings from operating a battery-electric car rather than a gasoline vehicle had increased by approximately 20% to 45% in most countries.

Some of the war-related behavior will reverse if oil becomes cheap again. Drivers may return to personal cars. Refiners may resume exports. Freight activity may recover. Yet vehicles purchased during the crisis will remain in service for years. Charging stations built in response to high oil prices will not disappear when a ceasefire is signed.

The same pattern followed earlier oil shocks. Price spikes encouraged efficiency, alternative fuels and smaller vehicles. Those changes reduced the oil intensity of future economic growth. The 2026 shock may do the same for electric mobility, especially in Asian countries that experienced the greatest physical exposure to Hormuz.

China’s Fuel-Export Curbs Reduced Crude Demand

One of the least visible but most powerful adjustments occurred inside refineries. China is not only an oil consumer. It is a major processor and exporter of petroleum products. A Chinese refinery may import crude, convert it into gasoline, diesel or jet fuel and sell part of the output elsewhere in Asia.

When Beijing restricted those exports in March, it removed export-market demand from the refinery system. China still needed crude for domestic consumption, but it no longer needed the same volume to supply overseas customers.

Refined-product exports totaled 23.59 million metric tons during the first half of 2026, down 13.2% from the same period of 2025. The policy protected domestic fuel availability and reduced the need to compete for scarce crude.

The effect extended beyond China. Countries that normally purchased Chinese gasoline, diesel or jet fuel had to seek alternative suppliers or reduce consumption. Some of the demand destruction was therefore transferred to other Asian markets. Regional refining margins rose, transportation costs increased and governments faced pressure to subsidize consumers.

China began lifting some export restrictions in July after the interim agreement. Zhejiang Petrochemical was permitted to resume shipments, and refiners planned approximately 3 million metric tons of exports for the month. That decision illustrates the connection between geopolitics and crude demand: when export permissions return, refineries have an incentive to raise utilization and import more feedstock. :contentReference[oaicite:12]{index=12}

The July easing also demonstrates why the June import collapse should not automatically be treated as a permanent baseline. Administrative controls can be reversed. Strong export margins can encourage refiners to restart. The market’s future balance depends partly on how aggressively Beijing allows product exports while Gulf supply remains unstable.

U.S. Oil Production Reached a Record at the Right Time

The United States entered the 2026 conflict in a fundamentally different position from the oil shocks of the 1970s. It was the world’s largest producer and a major exporter rather than an economy overwhelmingly dependent on imported crude.

U.S. output reached a record 13.93 million barrels per day in April. Production increased in the Permian Basin, where extensive pipelines, processing facilities, service companies and drilled inventory allowed producers to respond to higher prices faster than most conventional projects could.

Shale production is not instantaneous. Companies must secure equipment, complete wells, connect them to gathering systems and manage rapid decline rates. Publicly traded producers also face pressure to return cash to shareholders rather than pursue growth at any price.

Even so, shale operates on a shorter cycle than offshore megaprojects or new production in remote regions. A company can bring a previously drilled well online in months rather than waiting years for an entirely new field. The war’s elevated prices improved project economics and encouraged activity.

The U.S. contribution was larger than the April record alone. Strong domestic production reduced American demand for imported barrels, allowing Atlantic Basin supply to flow toward Europe and Asia. U.S. crude exports could replace certain grades lost from the Gulf, although differences in sulfur content, density and refinery configuration limited perfect substitution.

West Texas Intermediate also traded at a discount to Brent during much of the crisis. That price relationship encouraged exports while cushioning U.S. refiners relative to competitors more directly exposed to international supply.

Production in Canada, Brazil, Guyana and other parts of the Americas added to the Atlantic Basin response. No single producer replaced the missing Gulf barrels. Collectively, however, non-Middle Eastern supply prevented the shortage from becoming even larger.

Why U.S. Shale Could Not Replace Hormuz by Itself

The record output should not be misread as evidence that the United States could neutralize a 10-million-barrel-per-day disruption. The April increase was 216,000 barrels per day—meaningful but small compared with the scale of Middle Eastern shut-ins.

U.S. crude also faces infrastructure and quality constraints. Refineries are designed for particular combinations of light and heavy crude. Shipping millions of additional barrels to Asia requires tankers, export-terminal capacity and time. High interest rates, labor costs, water requirements and shareholder discipline limit how rapidly drilling can accelerate.

Shale was a buffer, not a complete substitute. Its importance was that it reduced the residual shortage after demand changes, reserve releases and rerouting were taken into account.

The Strategic Petroleum Reserve Bought Time

Emergency reserves are designed for precisely the type of disruption that occurred in 2026. They cannot create new oil, but they can move consumption from the present into the future by drawing down barrels accumulated earlier.

The IEA’s March decision made 400 million barrels available across 32 member countries. It was the largest coordinated action in the agency’s history. By late July, approximately 290 million barrels had already been released, while IEA countries retained more than one billion barrels in government-controlled stocks. :contentReference[oaicite:13]{index=13}

The United States authorized 172 million barrels from the SPR. Deliveries were planned over roughly 120 days, producing an average flow of approximately 1.4 million barrels per day if executed evenly. Actual weekly volumes varied, but the scale was large enough to influence physical availability and trader expectations.

By July 10, the U.S. reserve had fallen by 98.9 million barrels since the war began. Stocks reached 316.5 million barrels, their lowest level since April 1983. Combined commercial and strategic U.S. crude inventories also fell sharply. :contentReference[oaicite:14]{index=14}

Reserve releases affect prices through two channels. First, they put physical oil into the market. Refiners can purchase the barrels, reducing their need to bid for other supply. Second, they signal that governments will respond to disruption, discouraging traders from assuming every lost cargo must be reflected immediately in higher prices.

The second channel can matter before the barrels arrive. Futures markets incorporate expected supply. An announced release can reduce prices if participants believe it will be delivered and is suitable for refiners.

The Cost of Using Emergency Stocks

Drawing reserves is not free. It reduces protection against the next emergency. The U.S. SPR entered the crisis below its historical peak, and the 2026 release pushed it to a level last seen more than four decades earlier.

The Energy Department said it had arranged to replace approximately 200 million barrels within a year. Whether that timetable can be met depends on future prices, infrastructure, contractual terms and the continuation of the conflict.

Refilling the reserve while oil remains expensive could raise government costs and tighten the commercial market. Delaying replenishment would leave the country more exposed to another war, hurricane or infrastructure failure. The release therefore exchanged immediate price relief for reduced future optionality.

The SPR also contains crude rather than finished gasoline or diesel. Releasing oil helps only if refineries have capacity, appropriate configurations and distribution networks. During a product-specific shortage, crude stocks may be less effective than inventories of the missing fuel.

Still, the reserve achieved its primary purpose in 2026: it provided time for supply chains and consumers to adjust. Without it, the price needed to destroy demand would almost certainly have been higher.

Saudi Arabia Built a Partial Bypass Around Hormuz

Saudi Arabia’s East-West Pipeline became one of the most important pieces of infrastructure in the global economy after February 28. The line carries crude from eastern production regions across the country to Yanbu on the Red Sea, allowing cargoes to avoid Hormuz.

Exports from Yanbu rose to nearly 4 million barrels per day during the week ending March 22. Saudi Aramco said the pipeline could move as much as 7 million barrels per day, with approximately 5 million potentially available for export after domestic refinery requirements.

This did not fully replace the more than 7 million barrels per day of Saudi exports recorded in February, most of which had normally passed through Hormuz. It nevertheless reduced the net disruption by several million barrels per day and gave Asian buyers access to Saudi crude through a longer western route.

The alternative came with costs. Cargoes loaded at Yanbu and destined for Asia had to navigate the Red Sea and Bab el-Mandeb or take longer routes around Africa. Tanker availability, port capacity, storage, scheduling and security limited the theoretical pipeline capacity. A pipeline capable of moving crude does not automatically create equal loading capacity at the destination port.

The route also became a target. By late July, Yemen’s Houthis had threatened or attacked Saudi energy infrastructure and shipping connected to the Red Sea. The widening of the conflict exposed the central weakness in the bypass strategy: avoiding Hormuz only works if the alternative corridor remains secure.

When Red Sea traffic declined, some Saudi cargoes faced longer routes through the Suez system or around the Cape of Good Hope. Each additional day at sea increased freight costs, tied up tanker capacity and delayed delivery to refiners.

The UAE’s Fujairah Route

The United Arab Emirates also operates a pipeline from the Habshan production area to Fujairah, an export port outside the Strait of Hormuz. Combined with the Saudi route, the IEA estimated that approximately 3.5 million to 5.5 million barrels per day of available capacity could bypass Hormuz under favorable conditions.

The range is wide because nominal capacity differs from practical export capacity. Pipelines may already be partly utilized. Ports need available berths and storage. Crude grades must be segregated or blended. Producers need enough oil on the correct side of the system. Maintenance and security requirements can reduce throughput.

Iraq, Kuwait, Qatar and Bahrain lack comparable operational routes capable of replacing most of their seaborne exports. That asymmetry explains why production shut-ins were especially severe in Iraq and Kuwait. Oil that cannot be exported eventually fills local storage, forcing producers to reduce output even when wells and processing plants remain intact.

Unconventional Ship-to-Ship Transfers

Reuters also documented a U.S.-supported operation involving ship-to-ship transfers near Fujairah and Sohar. Smaller or specially routed vessels moved oil toward tankers waiting outside the most dangerous part of the Gulf. At least 116 ships had participated by mid-June, according to shipping data and satellite imagery reviewed by Reuters. :contentReference[oaicite:15]{index=15}

Such operations can preserve some trade but are inefficient compared with normal tanker movements. They increase handling, coordination and security costs. Ships may disable tracking systems or travel in protected convoys, reducing transparency. Insurers, traders and port authorities face additional legal and operational risks.

The ingenuity of these workarounds helps explain why oil did not reach $200. Their complexity explains why prices did not simply return to pre-war levels.

Physical Oil Was Scarce, but It Was Still Available

One of the more counterintuitive features of the crisis was the coexistence of severe disruption and continued physical availability. Buyers could still obtain crude, although often from different suppliers, at different locations, with longer voyages and higher financing or insurance costs.

The oil market is a network rather than a single pipeline. A refinery in South Korea that loses a Gulf cargo can seek crude from the United States, Brazil, Guyana, West Africa or the North Sea. The replacement may not be ideal, but blending and operational adjustments can make it usable.

Trading companies also reallocate cargoes. A barrel originally destined for Europe can be sent to Asia while Europe purchases another grade from a closer supplier. Prices and freight rates coordinate those movements. The process is expensive, but it prevents a local interruption from becoming an immediate global absence.

Inventories bridge the timing gap. Refineries maintain working stocks. Governments hold strategic reserves. Producers store crude near export terminals. Oil can remain on tankers as floating storage. Each layer gives the system time to redirect supply.

EIA data underscore both the severity and resilience of the adjustment. Global inventories were estimated to have fallen by an average of 5.1 million barrels per day in the second quarter and were forecast to decline by another 2.2 million barrels per day during the third. Those draws are not sustainable forever. They indicate that consumption exceeded current production and that stored oil supplied the difference.

The July EIA outlook expected the balance to reverse later. It projected an average inventory build of 2.7 million barrels per day in the fourth quarter of 2026 and 5 million barrels per day in 2027 as Middle Eastern production returned and supply again exceeded consumption. That forecast was completed before the latest late-July escalation and is therefore subject to unusually large uncertainty. :contentReference[oaicite:16]{index=16}

Prices stayed below $150 partly because traders believed the shortage was temporary. If that belief proves wrong, inventories will continue falling and the market will require a stronger price response.

The Difference Between a Barrel and the Right Barrel

Oil is often discussed as a uniform commodity, but crude grades differ in density, sulfur content, acidity and yield. A refinery designed for heavy, sour Middle Eastern crude cannot always replace it efficiently with light, sweet U.S. shale oil.

Substitution can reduce refinery output of diesel or other products even when total crude supply appears sufficient. A plant may need to blend several grades, operate units differently or accept lower margins. Maintenance schedules can become more complicated.

This helps explain why refined-fuel prices can rise faster than crude. The market may have enough barrels in aggregate while lacking the grades and products needed in particular regions. Jet fuel, diesel, marine fuel and petrochemical feedstocks can each develop separate shortages.

Transport capacity is another constraint. A barrel in Texas is not instantly available in Singapore. It must reach an export terminal, be loaded onto a tanker, cross an ocean, unload and move through a refinery. Financing costs accumulate during the voyage. The tanker itself becomes unavailable for other cargoes.

Longer routes effectively reduce the global shipping fleet’s capacity. If a voyage takes 50 days instead of 30, the same number of tankers can deliver fewer barrels per year. Freight rates rise even when no vessel has been destroyed.

These frictions increased the economic cost of the war without necessarily pushing the benchmark price above $150. Consumers paid through shipping, refining and regional-product premiums as well as through crude prices.

Why Political Headlines Burned Oil Bulls

The futures market does not wait for every tanker to move. It continuously reprices expectations about future supply and demand. During the 2026 war, those expectations changed with statements from Washington and Tehran.

President Trump repeatedly announced or suggested diplomatic progress, threatened renewed attacks and revised the United States’ operational posture. Each change could move oil by several dollars within hours. A trader holding a large bullish position might be directionally correct about tight physical supply and still lose money when an unexpected ceasefire announcement caused futures to collapse.

Reuters reported that many funds reduced bullish exposure in early July after repeated reversals. Ilia Bouchouev of the Oxford Institute for Energy Studies summarized the market as one in which participants were broadly bullish but reluctant to hold large long positions. :contentReference[oaicite:17]{index=17}

Lower liquidity can amplify volatility. When fewer traders are willing to take the opposite side of a transaction, a modest order can move prices further. Bid-ask spreads widen. Short-term price changes become less reliable indicators of the underlying physical balance.

The pattern was visible on July 27. Physical Hormuz traffic remained drastically below normal, and the Red Sea route was under threat. Yet Brent fell almost 9% because the United States paused airstrikes and traders increased the probability of a diplomatic resolution.

That does not mean the price decline was irrational. A settlement could restore millions of barrels per day of production and shipping. Futures represent expected conditions during the delivery period, not only the number of vessels passing on the day of the trade.

It does mean that oil became unusually sensitive to political credibility. A signed and enforceable agreement would have more durable value than a verbal pause. The June memorandum failed to resolve competing interpretations of who controlled passage through the strait. The market repeatedly paid for that ambiguity.

Why Speculators Did Not Force Oil Higher

Popular explanations sometimes blame speculators whenever commodity prices rise. In this case, speculative restraint may have limited the rally. Funds that had been hurt by sudden reversals became less willing to build positions based solely on worst-case forecasts.

A futures price can rise even when no physical barrel changes hands, but the position eventually has to be closed, rolled or settled. If traders believe governments will release reserves or announce another ceasefire, the risk of holding a $150 target becomes substantial.

The absence of a large speculative long does not prove the physical market is comfortable. It indicates that the financial reward for expressing the bullish view may be unattractive relative to the headline risk.

Why Brent Peaked Near $126 Instead of $200

Brent’s approximately $126 peak reflected a severe shortage, but not the full collapse embedded in the harshest scenarios. Several mechanisms prevented the price from moving further.

First, the market began rationing consumption before $150. High prices reduced driving, freight, aviation, petrochemical activity and refinery demand, particularly in Asia. Demand destruction does not begin at a single threshold. It accumulates as each consumer reaches a different limit.

Second, strategic releases added several million barrels per day during critical months. Those volumes were temporary, but the market needed temporary relief while trade routes adjusted.

Third, China did not replace its missing imports. It reduced crude purchases, product exports and refinery runs. That decision removed the largest potential source of competitive bidding.

Fourth, Saudi and Emirati pipelines bypassed part of Hormuz. Protected shipping and ship-to-ship transfers preserved additional flows.

Fifth, U.S. production reached a record, while other Atlantic Basin producers expanded exports. Those barrels could not fully replace Gulf supply but narrowed the deficit.

Sixth, traders continued to assign a meaningful probability to a ceasefire or reopening. The June agreement validated that expectation temporarily, sending Brent below $70 in early July.

Finally, $200 was always a scenario rather than a law. Commodity markets respond to feedback. The higher the price rises, the more forcefully governments, companies and consumers adapt. The forecast itself describes a world that begins changing as soon as the forecast appears likely to come true.

What the Crisis Revealed About Oil Demand

The most important long-term discovery may be that oil demand, especially in China, has become more flexible than historical models suggested.

Traditional short-run elasticity estimates were built during periods when nearly every road vehicle used petroleum. Commuters could drive less, combine trips or buy smaller cars, but they could not switch an existing gasoline journey to electricity without changing vehicles.

China’s transport system now includes millions of electric cars, electrified taxis, battery-powered buses, electric trucks and extensive rail. When gasoline prices rise, consumers can reallocate travel among existing modes rather than waiting years for the vehicle fleet to change.

Digital ride-hailing adds another layer. A passenger does not need to own an EV to benefit from electrification. An app can match the passenger with an electric taxi. The oil-saving asset is shared across many users.

Businesses can also optimize fleets more rapidly. A logistics company may assign electric trucks to high-mileage routes and reserve diesel vehicles for journeys where charging is difficult. That operating flexibility reduces fuel demand at the margin.

Petrochemical demand remains less flexible. Oil and natural-gas liquids are feedstocks for plastics, chemicals and industrial materials. Substitution is more difficult than in urban transportation. This is one reason long-term oil forecasts increasingly expect road-fuel demand to weaken while petrochemicals account for a larger share of remaining growth.

The war also highlighted the difference between gross domestic product and oil consumption. An economy can continue producing services, software, financial activity and electric transportation while using less petroleum. Oil intensity—the amount of oil required per dollar of economic output—can fall even when GDP grows.

This does not mean the end of oil demand is imminent. Aviation, shipping, heavy industry, petrochemicals and much of the global vehicle fleet remain dependent on petroleum. Emerging economies continue to add mobility. The lesson is narrower: a crisis may destroy less economic activity for each barrel of oil removed than older models assumed, particularly in electrified markets.

Historical Comparisons: Why 2026 Was Different

The 1973–1974 Embargo

The Arab oil embargo exposed an economy built around rapidly rising petroleum consumption, inefficient cars and limited strategic preparation. The United States was increasingly dependent on imports, and the International Energy Agency did not yet exist when the shock began.

Consumers had few alternatives to gasoline. Public transit was limited in many American cities. Electric vehicles were not commercially significant. Strategic stocks were less developed. Price controls and allocation rules complicated adjustment.

The crisis produced lasting changes: fuel-economy standards, strategic reserves, new production and a stronger focus on energy security. Those institutions helped manage later shocks.

The 1979 Iranian Revolution

The Iranian Revolution caused a smaller physical supply loss than public panic implied, but precautionary buying and inventory behavior magnified the price response. Buyers sought additional barrels simultaneously because they feared future scarcity.

The 2026 market contained a similar psychological element, but emergency releases and transparent global trading reduced the incentive to hoard indefinitely. China’s choice to reduce imports was the opposite of panic buying.

Iraq’s 1990 Invasion of Kuwait

The invasion removed Iraqi and Kuwaiti supply and sent prices sharply higher. Saudi Arabia and other producers had usable spare capacity outside the disrupted volumes and raised output. The conflict did not close Hormuz for months.

In 2026, much of the spare capacity was inside the region whose exports were constrained. The world therefore relied more heavily on inventories, demand reduction and non-OPEC production.

The 2008 Price Record

Oil approached $147 in 2008 during a period of strong emerging-market demand, limited spare capacity, financial investment in commodities and concern that production would struggle to keep pace with consumption. There was no single Hormuz closure equivalent to 2026.

The comparison shows why the 2026 ceiling is surprising. A genuine chokepoint disruption produced a lower nominal peak than the demand-driven boom of 2008.

Yet the demand backdrop was very different. China’s economy was expanding at a double-digit pace in parts of the pre-2008 cycle, and its vehicle fleet was overwhelmingly petroleum-based. In 2026, growth was slower, the property sector remained weak, refineries faced overcapacity and electrification was reducing road-fuel demand.

The 2020 Pandemic

The pandemic demonstrated that demand can collapse faster than supply. Travel restrictions and lockdowns removed tens of millions of barrels per day of consumption, briefly sending U.S. futures below zero because storage capacity was scarce.

The 2026 demand decline was far smaller and occurred for different reasons. People were often still traveling; they were using different modes or reducing discretionary petroleum use. The comparison shows that demand is not fixed, but it should not imply that the war replicated pandemic conditions.

Russia’s 2022 Invasion of Ukraine

The 2022 shock forced Europe to replace Russian energy and reorganize trade. Oil proved more fungible than pipeline gas: Russian crude was redirected toward Asia while other suppliers served Europe.

The 2026 crisis tested a more concentrated chokepoint. Gulf oil could not simply be redirected if it could not leave the producing region. However, the trade-reallocation experience gained after 2022 improved the ability of traders, shippers and governments to manage sanctions, longer voyages and alternative grades.

The Central Difference in 2026

Earlier crises changed energy systems after prices rose. In 2026, some of those changes already existed before the shock. Strategic reserves, U.S. shale, electric vehicles, high-speed rail, flexible global trading and bypass pipelines were available from the first months of the war.

The market was more resilient because it had learned from previous disruptions. It was also more complex, with vulnerability shifting from crude availability to shipping, refining, electricity, batteries, LNG and regional product markets.

The Effect on U.S. Gasoline and Inflation

Crude below $150 did not mean American consumers escaped the shock. Gasoline prices rose because crude became more expensive, refinery margins widened and product inventories tightened.

Crude generally represents the largest variable component of retail gasoline prices, but the relationship is not one-to-one. Refining costs, taxes, distribution, seasonal fuel specifications and local competition affect the final price.

The EIA’s July forecast expected regular gasoline to average just under $3.80 per gallon during the third quarter, down from more than $4.20 in the second. It projected approximately $3.40 in the fourth quarter as inventories rebuilt and summer demand ended. The agency forecast an annual average of $3.64 for 2026 and $3.09 for 2027. :contentReference[oaicite:18]{index=18}

Those projections are conditional. Renewed closure, attacks on refineries, disruption in the Red Sea or a rebound in Chinese imports could produce higher prices. A durable settlement could lower them.

Gasoline prices also decline more slowly than crude at times. Retail stations purchase fuel at different intervals. Refiners may retain wider margins when inventories are low. Distribution costs vary by region. Consumers often notice this asymmetry as prices rising quickly and falling gradually.

Energy affects inflation beyond the gas pump. Diesel raises freight and agricultural costs. Jet fuel affects airline fares. Petrochemical feedstocks influence plastics and packaging. LNG affects electricity and fertilizer. Companies may absorb some increases through lower margins, but prolonged costs are eventually passed through to customers.

Higher energy prices can also weaken demand for other goods. A household spending more on gasoline has less income available for restaurants, clothing or entertainment. The economic effect therefore includes both measured energy inflation and slower discretionary consumption.

For the Federal Reserve, an oil shock creates an uncomfortable combination. Headline inflation rises while economic growth may weaken. Monetary policy cannot reopen Hormuz or produce crude. Higher interest rates may suppress second-round inflation but also deepen the slowdown.

The fact that Brent did not reach $150 reduced those risks. It did not eliminate them.

Who Benefited and Who Was Hurt?

U.S. and Atlantic Basin Producers

Higher international prices improved cash flow for producers able to maintain or increase output. Companies with existing wells, export access and limited hedging could capture stronger realizations.

The benefit was not universal. Service costs rose. Companies with aggressive hedges may have sold production at predetermined prices below the spot market. Refiners could suffer if crude costs rose faster than product margins. Offshore operators faced shipping and insurance exposure.

Refiners

Refiners outside the Gulf benefited when product shortages widened crack spreads—the difference between the value of refined products and the crude used to make them. Plants configured to process alternative grades had an advantage.

Others struggled to source appropriate crude. A refinery dependent on Middle Eastern medium or heavy grades could face lower throughput even if light crude was available elsewhere.

Shipping Companies

Tanker owners could earn higher freight rates because voyages became longer and vessels avoided dangerous routes. War-risk premiums increased the cost of chartering ships.

The opportunity came with substantial danger. Vessels faced attack, detention, rerouting and uncertainty over insurance coverage. A high freight rate does not compensate for every potential loss.

Airlines and Logistics Companies

Fuel-intensive businesses were among the clearest losers. Airlines cannot electrify long-haul fleets in response to a five-month shock. Hedging can delay the effect, but contracts expire and counterparties charge for protection.

Trucking companies experienced a divided outcome. Operators with electric or LNG fleets gained a relative advantage, while diesel-dependent companies faced higher costs. China’s experience showed how fleet composition could become a competitive variable.

Petrochemical Companies

Petrochemical producers faced higher feedstock costs and weak demand in some markets. Chinese overcapacity compounded the pressure. Plants without access to competitively priced naphtha or LPG reduced operations.

Electric-Vehicle and Battery Companies

High gasoline prices strengthened the operating-cost case for EVs. Ride-hailing fleets and high-mileage commercial operators had the greatest incentive to switch because fuel savings accumulated quickly.

However, the broader war also increased prices for commodities, transportation and electronics. A weak economy can reduce all vehicle sales, including EVs. Energy security improved the strategic case for electrification without guaranteeing higher profits for every manufacturer.

Oil-Importing Governments

Governments in Asia faced higher subsidy costs, inflation and pressure on trade balances. Countries that cap retail fuel prices must absorb more of the international increase through public budgets or losses at state-owned energy companies.

Strategic reserves reduced immediate costs but created a future replenishment obligation. Importers with large storage capacity and diverse suppliers performed better than those dependent on just-in-time Gulf deliveries.

Why the Oil Market Remained More Fragile Than the Price Suggested

A price below $150 can create a false sense of security. Several indicators showed that the physical system remained under stress.

First, Hormuz traffic was still drastically below normal in late July. Barclays estimated net exports of crude and refined products through the strait at 2.9 million barrels per day during the week ending July 24, down from 5.9 million the previous week and far below the pre-war level.

Second, the Saudi bypass was exposed to Houthi attacks and Red Sea disruption. If Hormuz and Bab el-Mandeb were constrained simultaneously, the principal alternative route would lose much of its value.

Third, strategic reserves were declining. Emergency stocks can stabilize a temporary crisis but cannot support a permanent deficit of several million barrels per day.

Fourth, China’s low imports depended partly on inventory draws and administrative restrictions. A rebound could tighten the market rapidly.

Fifth, much of the world’s spare production capacity remained inside the Gulf. Restoring production after prolonged shut-ins may take time, particularly if infrastructure has been damaged or reservoirs require careful management.

Sixth, the futures market’s low liquidity increased the risk of abrupt moves. A thin market can fall sharply on diplomatic optimism and rise just as quickly when talks fail.

Seventh, LNG exposure remained substantial. Oil prices could appear contained while Asian or European gas markets experienced a more severe shortage.

Finally, political agreements lacked clarity and enforcement. The June memorandum did not resolve whether Iran could supervise, restrict or charge for transit. Without a shared interpretation, commercial shippers could not rely on the document as durable protection.

The Strongest Case That Oil Could Stay Below $150

The constructive interpretation begins with adaptation. The world has demonstrated that it can reduce consumption faster than expected. China’s oil demand is less rigid because of electrification, mass transit, inventories and a slowing industrial structure.

Non-Gulf supply continues growing. U.S. production is near record levels, while Canada, Brazil and Guyana add export capacity. High prices encourage maintenance, completion of drilled wells and optimization of existing fields.

IEA members still hold substantial emergency stocks. A large portion of the original 400 million-barrel release has entered the market, and more than one billion barrels of government-controlled reserves remained available in late July.

Saudi Arabia and the UAE have proven that bypass routes can handle meaningful volumes. Even if practical capacity is lower than the most optimistic engineering estimate, several million barrels per day materially reduce the shortage.

A negotiated management mechanism for Hormuz would restore flows before every political dispute is resolved. Commercial shipping does not require the United States and Iran to agree on all aspects of the war; it requires credible rules, security and insurance.

The EIA’s July outlook expected the market to return to oversupply after the transition period. It forecast Brent averaging $82 in 2026 and $65 in 2027, although the late-July fighting makes that projection especially uncertain.

If Gulf production returns while China’s structural oil demand remains weaker, inventories could rebuild rapidly. Under that scenario, the market may eventually conclude that the 2026 shock accelerated the arrival of surplus capacity rather than creating a lasting shortage.

The Strongest Skeptical Case

The skeptical interpretation begins with inventories. The world may have avoided $150 by consuming oil accumulated in earlier years. That strategy delays the reckoning but does not solve the underlying shortage.

If inventories continue falling by several million barrels per day, storage buffers will become inadequate. Buyers will then have to compete for current production, forcing prices higher until demand falls further.

China’s June imports may represent an emergency minimum rather than a sustainable level. Refineries need crude, product exports have economic value and strategic stocks eventually require replenishment. A return from 7.1 million to 10 million barrels per day would add nearly three million barrels per day of demand.

Saudi bypass routes could be disrupted. The Houthis’ effort to threaten the Red Sea demonstrates that the war can migrate geographically. Damage to the East-West Pipeline, Yanbu terminals or Bab el-Mandeb traffic would remove the most important alternative to Hormuz.

The U.S. SPR is at its lowest level since 1983. Another large release would deepen long-term energy-security concerns. Other IEA countries also face political limits on how much stock they are willing to use.

U.S. shale growth may slow if companies prioritize capital discipline or encounter cost inflation. The record April production increase cannot be extrapolated indefinitely. Wells decline rapidly, and maintaining output requires continuous investment.

Finally, the market’s reaction to political headlines may be too optimistic. A pause in bombing does not restore tanker traffic. A proposed framework does not guarantee safe passage. If repeated diplomatic failures convince traders that the conflict will last, the probability assigned to a prolonged shortage will rise.

Under that scenario, oil could still reach $150. The fact that it had not done so by July 28 is evidence of resilience, not proof that the risk has expired.

What Happened After the Reuters Analysis

The Reuters article and accompanying video were published on July 20 and 21. Their central question remained valid, but the market moved significantly in the following week.

Brent climbed above $100 as the conflict intensified and Houthi activity threatened Saudi oil infrastructure and the Red Sea route. The rise showed that the market remained capable of adding a large geopolitical premium when disruption spread beyond Hormuz.

President Trump then paused U.S. airstrikes. Brent fell 8.7% on July 27, while WTI lost 7.5%. The decline occurred before normal shipping resumed, reinforcing one of Zhdannikov’s central points: political announcements repeatedly punished traders who maintained large bullish positions.

By the morning of July 28, prices were near one-week lows but still well above their early-July levels. Hormuz exports remained subdued, and the Omani regional-management proposal was only a diplomatic initiative.

The update strengthens rather than weakens the broader analysis. Oil remained below $150 because the market expected adaptation and eventual reopening, but it continued moving violently as those expectations changed.

Three Scenarios for the Oil Market

Scenario One: A Credible Hormuz Agreement

In the most constructive scenario, Oman or another mediator secures a mechanism accepted by Iran, Gulf exporters and the United States. Commercial passage resumes under monitored rules. Insurers reduce war-risk premiums, and tanker traffic rises steadily.

Stranded cargoes would begin moving first. Production would follow as storage constraints eased. Saudi Arabia could continue using Yanbu while restoring eastern exports, creating a temporary surge in supply.

China would probably raise crude imports and refinery runs, partly offsetting the returning barrels. Strategic reserves would begin shifting from release toward replenishment. Even so, the initial supply response could exceed demand growth and push Brent lower.

The principal risk in this scenario is that markets price normalization faster than physical systems can deliver it. Production shut in for months may require inspection and maintenance. Ports and pipelines could face bottlenecks. A settlement would change direction immediately but not complete recovery overnight.

Scenario Two: Prolonged Partial Disruption

In the middle scenario, Hormuz remains open only intermittently. Protected convoys, Iranian-controlled channels, ship-to-ship transfers and bypass pipelines preserve some exports, but traffic remains far below normal.

Oil would likely stay volatile. Strategic releases and weak demand could cap rallies, while declining inventories would support prices during selloffs. Brent might repeatedly move between levels associated with diplomatic optimism and renewed military risk.

China would remain the central balancing force. If it maintained low imports, the market could function. If it replenished inventories aggressively, prices could rise sharply.

This scenario would impose the greatest cumulative economic cost. Even without a spectacular $200 spike, months of elevated freight, insurance, fuel and financing expenses would weigh on global growth.

Scenario Three: Simultaneous Hormuz and Red Sea Disruption

The most dangerous scenario would combine severe Hormuz constraints with a credible blockade or sustained attacks around Bab el-Mandeb and Yanbu.

Saudi Arabia’s western bypass would lose access to Asian markets through the shortest route. Tankers might travel around the Cape of Good Hope, adding time and reducing effective fleet capacity. Insurance costs would rise sharply.

Emergency reserves would become more important just as they were being depleted. LNG and refined products could face separate shortages. Asian importers might compete aggressively for Russian, American, African and Latin American cargoes.

Under those conditions, the assumptions that kept Brent below $150 could fail simultaneously. Demand destruction would have to become more severe, perhaps through recession rather than voluntary switching.

What Investors and Businesses Should Watch

The most useful indicators are physical rather than rhetorical. Daily vessel counts through Hormuz show whether commercial traffic is actually recovering. Export volumes from Yanbu reveal the strength of the Saudi bypass. Ship movements through Bab el-Mandeb indicate whether the Red Sea remains usable.

Chinese customs data are equally important. A rebound in crude imports would signal that refineries are returning and inventories may need replenishment. Refinery utilization and product-export quotas provide early evidence of that change.

Weekly strategic-reserve data show how much of the balancing burden is being carried by stored oil. A slowing release combined with weak Gulf exports would tighten the market.

U.S. production data indicate whether shale is sustaining its response. Monthly figures are more reliable than weekly estimates, although they arrive with a lag.

Refining margins help distinguish crude availability from product scarcity. Diesel or jet-fuel cracks can rise even when Brent falls, indicating that the shortage has moved downstream.

Finally, businesses should separate a temporary ceasefire from a durable shipping agreement. The market value of diplomacy depends on implementation, monitoring and the willingness of insurers and shipowners to return.

Risks and Uncertainties

• Renewed military escalation: U.S. and Iranian statements left open the possibility that strikes could resume.
• Red Sea disruption: Attacks on Saudi infrastructure or Bab el-Mandeb shipping could weaken the principal alternative to Hormuz.
• Chinese restocking: China may need to rebuild inventories and raise refinery runs after months of low imports.
• Strategic-reserve depletion: Governments have less protection after releasing hundreds of millions of barrels.
• Infrastructure damage: Pipelines, ports, refineries and production facilities may require repairs before normal output returns.
• Product shortages: Adequate crude supply does not guarantee sufficient diesel, jet fuel, gasoline or petrochemical feedstocks.
• LNG exposure: Qatar and the UAE remain heavily dependent on Hormuz for gas exports.
• Forecast uncertainty: Official outlooks were prepared before some of the latest military and diplomatic developments.
• Low market liquidity: Reduced participation can magnify price movements in both directions.
• Economic demand destruction: If voluntary conservation is insufficient, high prices may reduce demand through weaker growth and recession.

Frequently Asked Questions

Why did oil prices not reach $150 after the Strait of Hormuz closed?

Demand fell while alternative supply increased. China sharply reduced crude imports and refinery operations, consumers shifted toward electric transport, IEA countries released emergency stocks, U.S. output reached a record and Saudi Arabia redirected oil through the Red Sea. Traders also expected that the closure would eventually ease.

How high did Brent crude rise during the 2026 U.S.-Iran war?

Brent futures peaked at approximately $126 a barrel during the first five months of the conflict. That was far above pre-war levels but below the nominal record of almost $147 reached in 2008.

How much oil normally passes through the Strait of Hormuz?

Nearly 20 million barrels per day of crude, condensate and petroleum products passed through Hormuz in 2025. The total represented roughly one-quarter of seaborne oil trade and close to one-fifth of global oil consumption.

How much did China cut crude imports?

China imported 7.12 million barrels per day in June 2026, its lowest monthly volume since October 2016. The figure was 41.3% below the year-earlier level and approximately five million barrels per day below common pre-war import rates.

Did electric vehicles really reduce oil prices?

EVs were one contributor rather than the only cause. China’s large electric fleet allowed travel to shift away from gasoline and diesel without an equivalent reduction in mobility. The IEA estimated that Chinese EVs were already displacing around one million barrels per day of oil demand in 2025.

How much oil did the United States release from the Strategic Petroleum Reserve?

The U.S. government authorized 172 million barrels as part of the IEA’s 400 million-barrel coordinated emergency action. By July 10, U.S. SPR inventories had fallen by 98.9 million barrels since the war began.

How did Saudi Arabia bypass the Strait of Hormuz?

Saudi Arabia moved crude through its East-West Pipeline to Yanbu on the Red Sea. Yanbu exports approached 4 million barrels per day in late March, partially replacing shipments that normally left the Persian Gulf through Hormuz.

Could oil still reach $150?

Yes. A simultaneous disruption of Hormuz and the Red Sea, renewed attacks on infrastructure, a rebound in Chinese imports or exhaustion of strategic reserves could produce another major rally. Staying below $150 through July does not eliminate the risk.

Why did oil fall sharply on July 27?

Prices fell after President Trump paused a renewed U.S. air campaign and said talks with Iran were progressing. Brent settled 8.7% lower at $88.36, even though physical traffic through Hormuz remained severely constrained.

What is the most important indicator for future oil prices?

Actual shipping and export volumes through Hormuz are more informative than political statements alone. Chinese crude imports, strategic-reserve releases, Yanbu exports and Red Sea vessel traffic are also critical.

What did the EIA forecast for Brent crude?

In its July 7 Short-Term Energy Outlook, the EIA forecast Brent averaging $82 in 2026 and $65 in 2027. The forecast was completed before some of the latest July escalation and should therefore be treated as conditional rather than certain.

Does lower crude immediately mean cheaper gasoline?

No. Gasoline can decline more slowly because refiners, wholesalers and retailers purchase fuel on different schedules. Low product inventories and high refinery margins can keep retail prices elevated after crude falls.

Final Assessment

The most important lesson from the 2026 oil shock is not that Hormuz has become less important. The strait remains the world’s most consequential energy chokepoint, and the disruption removed or stranded an extraordinary volume of crude, refined products and LNG.

The lesson is that the rest of the system became more adaptable. China could reduce imports by millions of barrels per day because it had inventories, administrative control over refiners, weak industrial demand, extensive mass transit and the world’s largest electric-vehicle fleet. The United States could increase production and release strategic stocks. Saudi Arabia could redirect crude to the Red Sea. Traders could reorganize cargoes across the Atlantic Basin.

Those adjustments explain why Brent peaked near $126 rather than moving directly to $150 or $200. They do not make the war economically harmless. The cost appeared in lower inventories, higher shipping and insurance expenses, weak refinery utilization, regional fuel shortages, government subsidies and slower economic activity.

The strongest case for lower prices is that restored Gulf production will meet structurally weaker oil demand, creating renewed oversupply. The strongest concern is that the market has been surviving on temporary measures—inventory draws, emergency releases and depressed Chinese imports—that cannot continue indefinitely.

As of July 28, diplomacy had again reduced the price before it restored the barrels. That gap between financial optimism and physical supply is the central uncertainty. A credible and enforceable Hormuz arrangement could justify the market’s relief. Another failed pause, especially alongside Red Sea disruption, could expose how little spare protection remains.

Oil stayed below $150 because consumers, producers and governments changed their behavior. Whether it remains there depends on whether those adaptations last longer than the war.

Sources

• Reuters: Why oil prices haven’t gone crazy despite five months of U.S.-Iran war
• Reuters: China’s June oil imports hit a near ten-year low
• Reuters: China turns to electric taxis to soften the Hormuz oil shock
• Reuters: China lifts fuel-export curbs for July
• Reuters: U.S. oil production rises to a record high in April
• Reuters: U.S. strategic crude stocks fall to their lowest level since 1983
• Reuters: Saudi Arabia increases Yanbu crude exports
• Reuters: Ship-to-ship transfers used to move Gulf oil
• Reuters: Oil settles lower after the United States pauses attacks
• Reuters: Oil trades near a one-week low on July 28
• Reuters: U.S.-Iran talks, military pause and Hormuz dispute
• Reuters: Oman proposes a regional Hormuz management mechanism
• U.S. Energy Information Administration: July 2026 Short-Term Energy Outlook
• U.S. Energy Information Administration: Global Energy Security Data
• U.S. Energy Information Administration: First-quarter 2026 petroleum-market analysis
• International Energy Agency: Strait of Hormuz oil and LNG data
• International Energy Agency: 400 million-barrel emergency release
• International Energy Agency: July update on emergency-stock releases
• International Energy Agency: Global EV Outlook 2026
• U.S. Department of Energy: 172 million-barrel SPR authorization
• Columbia Center on Global Energy Policy: China’s exposure to Middle Eastern energy

Affiliate disclosure: Businessfinance.news may earn compensation from qualifying actions completed through selected links on this website, at no additional cost to the reader. Affiliate relationships do not influence our editorial reporting, analysis, or conclusions.