This article first appeared in The Edge Malaysia Weekly on July 20, 2026 - July 26, 2026

FOR almost three weeks after Washington and Tehran signed a memorandum of understanding (MoU) on June 17, the oil market convinced itself the worst was over. Analysts slashed price forecasts, hedge funds unwound geopolitical bets and Brent crude oil slipped back to US$72 a barrel in early July as traders priced in returning Middle Eastern supply and an impending glut.

Then the ceasefire collapsed — and the repricing was anything but gradual.

After Iranian missiles struck commercial vessels in the Strait of Hormuz in early July, the US launched successive waves of strikes on Iranian coastal military assets and revoked a temporary waiver allowing Iranian oil sales. Iran retaliated with drone and missile attacks on US bases in Kuwait and Bahrain, and struck two United Arab Emirates (UAE) supertankers transiting the strait, killing one crew member. Tehran declared the waterway closed “until further notice” and Washington reimposed a naval blockade of Iranian ports.

Brent crude responded by surging 9.6% on July 13 before touching US$87 a barrel the following day — up roughly 19% from its pre-war February level, and more than US$12 above where it traded barely a week earlier. The benchmark was trading at US$85.72 a barrel at press time.

The volatility exposed the market’s biggest blind spot: While oil futures signalled abundant supply, the physical market had been telling a far tighter story all along. The divergence is a defining theme for oil in the second half of 2026 — and the past week suggests the physical market is winning.

“The paper market has become disconnected from physical reality. Crude is being priced for a reopening that hasn’t happened and a glut that isn’t here,” Tracy Shuchart, chief market strategist at Hilltower Resource Advisors, said in a July 6 note to clients, before the latest escalation.

Her argument was simple. Total US crude inventories, including the Strategic Petroleum Reserve (SPR), are at their lowest since 1984. Saudi Aramco and Abu Dhabi National Oil Co (ADNOC) have both publicly suggested the market is unlikely to fully rebalance until 2027. Yet oil futures, until last week, were trading as if the disruptions would soon disappear.

Shuchart is known for her bullish call on the post-pandemic energy cycle, having noted underinvestment in the upstream segment and ESG-driven capital discipline would create structural supply shortages.

For Malaysia, the outcome matters far beyond the price of Brent crude itself. Prolonged physical tightness would influence everything from fuel subsidy reforms and inflation to national oil company Petroliam Nasional Bhd’s (PETRONAS) petroleum income and refining margins, particularly for operators benefiting from elevated product cracks rather than outright crude oil prices.

The speed of the post-MoU sentiment shift surprised even analysts who had expected prices to ease. UBS, in its July 1 report, cut its average 2026 Brent forecast by US$9 a barrel to US$84 and its 2027 projection by another US$10 to US$75. OCBC commodities strategist Sim Moh Siong lowered his year-end target to US$75, citing softer physical indicators such as Dated Brent trading below futures and a return of contango — a market structure in which future prices trade above spot prices, typically signalling that supply is expected to loosen. The prevailing view quickly became that geopolitical risk had been priced out.

Not everyone agreed.

“I would not go as far as saying the market has moved past the conflict,” Yaw Yan Chong, director of research at Wood Mackenzie, tells The Edge, as renewed fighting sent prices surging. He argues that investors had underestimated how much supply remained vulnerable: production of roughly 11.5 million barrels per day (bpd) across Saudi Arabia, Iraq, the UAE, Kuwait and Qatar — about 11% of global oil supply — had been shut in before the ceasefire even took effect, and nearly one-fifth of global supply normally transits the Strait of Hormuz. The market had been assuming normalisation long before physical infrastructure recovered.

The International Energy Agency’s (IEA) latest monthly report, published on July 10, quantified the gap: global supply rose 4.1 million bpd in June following the agreement, but remained 9.4 million bpd below pre-war levels.

Shuchart had warned that the arrangement rested on a 60-day MoU that postponed negotiations over Iran’s nuclear programme rather than resolving them. Her concern was borne out by subsequent events. After Iranian attacks on commercial vessels, the US Treasury revoked its 60-day waiver on Iranian oil sanctions, barring transactions after July 17.

“A market that completely unwinds the geopolitical premium is effectively pricing the probability of another disruption at zero. But it isn’t zero,” said Shuchart. The past week has demonstrated exactly how far from zero it was.

The escalation has also produced a new variable: direct US administration of the world’s most important oil chokepoint.

US President Donald Trump announced on July 13 that Washington would reimpose a blockade of Iranian ports — that all cargo ships transiting the Strait of Hormuz would pay a 20% fee for US military protection. The proposal drew immediate opposition from shipping operators, allies and even some Republicans in Congress, while the International Maritime Organization said mandatory tolls in the strait would be illegal.

By Tuesday, Trump had walked back on his plan, telling reporters his mind was changed by Gulf leaders themselves. “They said, ‘We’d love to do it a different way,’” he said in the Oval Office, recalling their offer to “invest tremendously in the United States, as opposed to charging a fee”. He had viewed the fee as “a reimbursement” for US protection of the waterway, but said of the new arrangement: “They’re investing and they’re getting a return on their money … and I like that much better.”

For the oil market, the episode cuts both ways. The retreat from tolls removed one cost layer on Gulf crude. But the underlying message — that transit through the Strait of Hormuz now depends on US military escort and shifting political arrangements — is hardly the normalisation future prices had assumed. DBS Research had already warned that Iran’s own transit tolls, introduced in mid-May, could outlast the hostilities, permanently raising shipping and insurance costs. The strait now has two self-appointed toll keepers, and neither arrangement rests on settled law.

Before the escalation, headlines suggested oil was flowing freely again through the Strait of Hormuz. The recovery, always partial, has now collapsed.

At its post-MoU peak, shipbroker BRS counted 98 tankers transiting in the week of June 22 to 28 — roughly 14 a day, still well below the pre-February norm of around 130 daily crossings. OCBC estimated tanker movements had recovered to only 30% of normal levels. UBS put it closer to 50%. That debate is now moot. MarineTraffic recorded just 57 transits from Friday to Sunday (July 10 to 12), down more than 50% from the week before, while Kpler counted six vessels on Sunday (July 12) alone — a five-week low.

Even before the collapse, Shuchart argued shipping was occurring largely on Iran’s terms, with the Islamic Revolutionary Guard Corps requiring vessels to follow approved corridors around Larak Island for inspection. The missile strike on the two UAE tankers — hit in the southern lane, in Omani territorial waters — showed even the routes considered the safest are not.

Beyond the strait, another bottleneck worries analysts. Yaw says Iran has signalled it could rely on its Houthi allies to target the Bab-el-Mandeb Strait. With the Strait of Hormuz compromised, Saudi Arabia has leaned heavily on its East-West Pipeline to the Red Sea port of Yanbu, from which shipments continue through Bab-el-Mandeb.

“If Bab-el-Mandeb were also disrupted, Saudi Arabia would effectively lose its remaining major export route,” says Yaw.

Wood Mackenzie believes such a scenario could push Brent crude beyond its 2008 record of US$147 a barrel — and under prolonged disruption of both chokepoints, possibly towards US$200. That remains a tail risk, but after a week during which supposedly safe lanes were struck by cruise missiles, it is one the market can no longer price at zero.

One of the biggest misconceptions, according to Hilltower’s Shuchart, is that restoring tanker movements equals restoring supply. “They’re completely different problems,” she noted in her report. Shipping is a logistical exercise measured in weeks. Restoring damaged reservoirs and processing plants can take months or years. The clearest evidence comes from ADNOC itself: ADNOC Gas disclosed that the Habshan complex — about 60% of its gas processing capacity — was damaged in early-April strikes, and expects to restore only around 80% of pre-conflict capacity by the fourth quarter of 2026, with full recovery not anticipated until mid-2027.

That broadly aligns with IEA estimates that while roughly half of affected Gulf production could return within two weeks and another 30% within six, the remaining 20% — 2.5 million to 3 million bpd — faces greater technical challenges, as prolonged shut-ins can permanently damage reservoir pressure and well integrity. ANZ Research from Down Under believes one million to two million bpd could ultimately be lost on a permanent or semi-permanent basis. Against that backdrop, both Aramco’s Amin Nasser and ADNOC’s Sultan Al Jaber have publicly suggested full rebalancing is unlikely before 2027.

Not all developments had been negative. Saudi exports recovered to about 4.52 million bpd in June — roughly 90% of pre-war levels — while the UAE lifted production to a record 3.7 million to 3.8 million bpd via its Fujairah pipeline, which bypasses the Strait of Hormuz.

But Yaw cautions against reading these as evidence of surplus. “The announced Opec+ production increases are largely academic. If exports remain constrained, the oil simply cannot leave the Gulf,” he says.

If the market remained surprisingly calm through months of conflict, it is because three cushions absorbed the shock: releases from floating storage; a coordinated strategic reserve drawdown; and a collapse in Chinese crude imports as Beijing ran down inventories. “These are finite buffers. They cannot sustain the market indefinitely,” says Yaw.

For Shuchart, the reserve draw “was the biggest cushion of all and is now the biggest looming bid”. The IEA coordinated the largest emergency release in its history in March — 400 million barrels, with the US contributing 172 million over a 120-day discharge — and even that was worth only about 16 days of transit through the Strait of Hormuz, she noted. “Every one of those barrels has to be bought back.”

The US structured its contribution as an exchange that must be returned with a premium, and Washington has said it intends to more than replace what it released. China is set to refill. India, which drew its own strategic reserve down to roughly 64% during the crisis and pointedly opted out of the IEA release on an “India first” basis, is fast-tracking storage expansion.

June Goh, senior oil market analyst at Sparta Commodities in Singapore, shares the concern, telling Al Jazeera that crude oil is “fast losing its strategic petroleum reserve buffer” and a “violent repricing up cannot be discounted” until rhetoric cools.

The demand side is stirring, too. As prices eased in early July, Chinese independent refiners, or “teapots” — which had slashed operating rates to a four-year low of 66.3% in May — resumed buying Middle Eastern cargoes almost immediately. JP Morgan estimates about three million bpd of China’s earlier import decline could reverse from August as inventories are rebuilt.

All told, UBS estimates global replenishment demand could approach one billion barrels — at two million bpd, well over a year of buying. “The market keeps focusing on future supply. It pays much less attention to future demand that’s already committed,” says Shuchart.

Even after last week’s surge, the flat price may still understate physical tightness. For Yaw, the key indicator bridging financial and physical markets is the spread between the Brent front-month futures contract and Dated Brent, the benchmark for physical North Sea cargoes — known as the Dated-to-Frontline (DFL) spread.

It has remained relatively narrow, at premiums of under US$2 a barrel, although it has climbed steadily from negative territory since Trump declared the ceasefire to be over. That is still well below its wartime peak of nearly US$14 a barrel, reached when Dated Brent averaged close to US$133 until the first half of April — a measure of the acute physical tightness at the time.

Since the conflict began, the market has been heavily driven by headlines, Yaw notes. But the critical underlying factors to watch are physical fundamentals, he argues, particularly tanker flows and crude inventory levels in key importing countries such as China and India.

Crack spreads matter just as much because they reflect the availability of refined products, he adds. “If crude supply is disrupted, product supply will inevitably follow.” At the outset of the war, major refining and export hubs — including India, China and South Korea — sharply curtailed product exports to safeguard domestic supply, with significant knock-on effects for import-dependent countries such as Australia and the Philippines.

That is exactly where Shuchart was looking. The benchmark 3-2-1 spread on Brent crude — the margin from refining three barrels of crude into two of gasoline and one of distillates — surged to a record high of nearly US$55 a barrel, roughly 3.6 times its January low, even as Brent eased off the highs reached at the peak of the US-Iran war.

The divergence reflects a shortage not of crude, but of the heavier Middle Eastern grades that yield more diesel and jet fuel. Singapore jet fuel prices have climbed roughly 140% since the conflict began.

“If crude had appreciated by the same magnitude as jet fuel, Brent would be trading closer to US$175,” said Shuchart.

The inventory data points the same way. Total US crude stocks, including the SPR, stood at roughly 726 million barrels for the week ended July 10, the lowest since May 1984; commercial inventories, at roughly 410 million, are the lowest since 2018; while Cushing hovers near operational minimums. DBS notes that OECD inventories are at their lowest since 1992, with global import cover approaching 70 days — near what many analysts consider a stress threshold of around 80 days.

Even after the past week, the argument for lower prices has not disappeared. Opec+ continues to unwind production cuts faster than expected. The IEA estimates that supply growth of 950,000 bpd this year will outpace demand growth of 720,000 bpd, implying a genuine surplus once Middle Eastern exports normalise. Morgan Stanley still forecasts a glut, while China’s Sinopec has repeatedly brought forward its estimate for peak domestic oil demand.

Fabien Yip, a market analyst at IG in Sydney, argued in a client note that a repeat of the war’s earlier price spike appears unlikely, with demand slow to recover while stranded-tanker releases and Opec+ quota expansion add barrels to an oversupplied outlook. Chris Pedersen of Pedersen Asset Management goes further: drone warfare has pushed buyers to diversify beyond the Middle East — a structural shift he believes supports Brent crude below US$61 a barrel in the longer term.

Even Yaw sees room for a sharp fall under a lasting peace. “If Hormuz genuinely returns to normal, we could see a flood of delayed Gulf exports entering the market as producers rush to recover lost revenues.”

The oil bears see the world as having far more optionality than the high oil price narrative suggests. 

Oil-producing countries outside the Gulf, including the US,  have been ramping up production to earn more petroleum dollars.  Furthermore, Saudi Arabia and the UAE are trying to bypass the Strait of Hormuz by using their pipeline to export oil.

Meanwhile, importing nations are diversifying, with the US, Brazil, West Africa and Russia being the primary beneficiaries of the redirection. At the height of the disruption, Japanese refiners bought a potentially record 13 million barrels of US crude in a single month, Chinese refiners ordered nine million barrels of West African grades alongside Brazilian cargoes, and the premium for US crude delivered to Asia nearly tripled in two months to over US$16 a barrel above Dubai benchmarks.

Russia has been a quieter winner, with its export revenues nearly doubling in February and March as Asian buyers absorbed discounted Urals and ESPO barrels. However, the substitution has hard limits. Asia takes roughly 16 million bpd of Middle Eastern crude, and “even replacing a modest share of that with Atlantic Basin supply is not feasible”, says Richard Jones of Energy Aspects, which is why every redirected cargo commands a premium, not a discount.

But every bearish forecast rests on one assumption: that Middle Eastern supply returns smoothly and sustainably. The past week has made that assumption harder to defend than at any point since the MoU was signed — ADNOC’s restoration timeline stretches into 2027, US inventories sit near four-decade lows and the strait itself is once again a battlefield.

“The market is pricing barrels that don’t exist yet. If those barrels don’t show up, the repricing won’t be gradual,” Shuchart warned before the escalation.

It wasn’t. The question now confronting governments, refiners and producers across Asia — Malaysia included — is whether last week’s surge in oil price was a repricing or merely its beginning.

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