The Oil Market Is Pricing Two Realities at Once

DHAHRAN — The oil market has split in two, and Saudi Arabia is trapped in the gap. Dated Brent — the price at which actual, physical barrels change hands in the North Sea — closed at $131.97 on April 10, while ICE Brent futures for front-month delivery settled near $97, a spread of roughly $35 that has no precedent in the nearly four decades since S&P Global Platts began publishing the assessment. This is not a pricing anomaly to be arbitraged away by clever traders; it is the market simultaneously screaming two contradictory truths — that physical oil is desperately scarce right now, and that it expects the scarcity to end soon enough that forward delivery should be priced for peace.

For Aramco, the consequences are immediate and structural. Its May Official Selling Price was calibrated to a world where Brent traded at $109, and that world lasted roughly seventy-two hours. The OSP now sits $22 below what physical barrels actually cost and $13 above what futures say they should cost in June — a pricing no-man’s-land that will define the most contentious term-contract renegotiation cycle in the company’s history when the June OSP announcement window opens around May 5.

What Is the Dated Brent Super-Contango and Why Does It Matter?

Every afternoon at 16:30 London time, S&P Global Commodity Insights runs its Market on Close process — the window during which traders submit bids, offers, and completed deals for physical North Sea cargoes loading ten to thirty days forward. The resulting number is dated Brent, and it is the single most consequential price in global energy because it anchors roughly 80% of the world’s internationally traded crude. It reflects what a refiner will actually pay to put a barrel on a ship this month, not what a speculator thinks a barrel might be worth when a futures contract expires.

The spread between dated Brent and ICE Brent futures — known as the exchange of futures for physical, or EFP — normally ranges between $0.50 and $2.00. On April 10, it was $35. On April 7, when dated Brent hit its all-time high of $144.42, the intraday spread touched $47. To put this in mechanical terms: arbitrageurs exist precisely to close gaps like this, buying the cheaper instrument and selling the dearer one until the spread compresses. A $35 EFP persists only when the physical supply is genuinely, structurally unavailable — when there are no barrels for the arbitrageur to buy and deliver against the paper position.

Morgan Stanley described it with unusual directness: the Hormuz disruption “prompted a much more violent shock in physical Brent-linked barrels compared to the main financial contract of Brent futures.” Amrita Sen of Energy Aspects, speaking to CNBC on April 8, was blunter: the futures price, she argued, was masking the true tightness showing up everywhere else — and giving traders a false sense of security that things were not that stressed.

A Market That Cannot Agree With Itself

What makes this spread historically unique is not its size — though $35 dwarfs any prior dislocation — but its cause. The 2008 dated Brent record of $144.22 was driven by demand-side speculation in a market where physical supply, while tight, was accessible. Tankers moved. Ports loaded. The forward curve reflected a single consensus about where prices were heading. In April 2026, there is no single consensus because there are, functionally, two oil markets operating under different physical realities.

The first market is the trapped-barrel market: roughly 4 to 7 ships per day are transiting Hormuz against a pre-war baseline of 138, according to Windward maritime tracking data. Kpler estimates a seaborne export deficit from the Gulf of approximately 6 million barrels per day. Iraqi exports have collapsed from 4 million to roughly 900,000 bpd. Saudi Arabia, the UAE, and Kuwait have collectively lost 9.15 million bpd of export capacity that cannot reach eastern buyers through the Strait. In this market, dated Brent at $132 is rational — possibly even low, given that Goldman Sachs called the Hormuz shutdown “the largest supply shock in the history of the global crude market.”

The second market is the ceasefire-optimism market, where futures traders are pricing a gradual recovery of Hormuz flows over the next sixty to ninety days. The forward curve tells this story clearly: June 2026 ICE Brent at $109.11, July at $99.25, December at $79.92. Goldman’s base case assumes 10% of normal flows for twenty-one days, then a thirty-day gradual recovery. If that timeline holds, front-month futures at $97 are defensible. The problem is that the ceasefire, as Janiv Shah of Rystad Energy noted on April 9, represents “formalization of existing conditions, where passage remains contingent on coordination” — the strait is technically open and functionally closed, and the futures market is betting on a resolution that the physical market has not yet seen any evidence of.

How Does the $35 Spread Trap Aramco’s OSP Architecture?

Aramco’s Official Selling Price system was designed for a world where dated Brent, futures, and the Oman/Dubai benchmark moved within a few dollars of each other — not a world where they disagree by $35. Each month, around the 5th, Aramco announces a per-barrel differential over the average of Oman and Dubai assessments for Asian buyers, over ICE Brent for European buyers. The differential tells refiners what premium or discount they will pay relative to the benchmark for the grade they have contracted to lift. In normal conditions, this is a calibration exercise. In April 2026, it is an impossible positioning problem.

The May OSP for Arab Light to Asia was set at +$19.50 over Oman/Dubai — the highest differential in Aramco’s history, a $17.00 single-month increase from April’s +$2.50. It was set when Brent traded near $109. Bloomberg’s survey of traders anticipated a differential of +$40, meaning Aramco deliberately left an estimated $20.50 per barrel on the table — a restraint that looked like diplomatic generosity in early April and now looks like a miscalculation from both directions simultaneously. At $132 physical, term buyers are getting May barrels at a discount of roughly $22 to what the same grade would fetch on the spot market. At $97 futures, those same buyers are paying $13 above what the forward curve says oil should cost when the cargo actually loads.

For European buyers, the exposure is worse. The May OSP for northwest Europe was set at +$27.85 over ICE Brent — a $25 single-month increase. European refiners are absorbing this differential against a futures curve that is telling them June barrels will be cheaper, making every term-contract lift a bet against the market’s own forward expectations.

The structural problem is that Aramco cannot reprice May cargoes retroactively. The OSP is a commitment. Term buyers who signed contracts committing to lift 300,000 or 500,000 barrels per day did so on the assumption that the pricing mechanism would track market reality. When the mechanism produces a price that is simultaneously too cheap for the physical market and too expensive for the paper market, it satisfies no one — and everyone will remember this when June negotiations open around May 5.

Iran’s Perverse Incentive: Higher Physical Prices, Bigger Franchise Revenue

The super-contango creates an incentive structure that runs exactly counter to any ceasefire logic. Iran has conducted at least 34 tracked oil loadings from Kharg Island since the conflict began, generating an estimated $3.5 billion in revenue, according to Bloomberg tanker-tracking data — making Iran, as Bloomberg described it on March 26, “the only exporter out of Hormuz.” The IRGC’s toll architecture — $2 million per VLCC, payable in Chinese yuan via Kunlun Bank or USDT on the Tron blockchain — functions as a fixed levy on every vessel the IRGC chooses to exempt from the blockade.

At ten VLCCs per week, the toll generates roughly $20 million in weekly revenue for the IRGC — a number that is structurally independent of oil price. But the franchise value of being the sole gatekeeper increases with every dollar the physical-paper spread widens, because the scarcity that inflates dated Brent is the scarcity Iran controls. When a VLCC carrying two million barrels loads at Kharg and transits Hormuz under IRGC escort, the cargo is worth $264 million at $132 physical — against which the $2 million toll is 0.76%, a rounding error that the Chinese buyer will pay without hesitation. The higher physical prices climb, the more Iran profits from both its own exports and its gate-keeping function, and the less incentive it has to fully reopen the strait.

Iran’s parliament formalized this logic before the ceasefire existed. The “Strait of Hormuz Management Plan,” passed March 31, reframes the waterway as a “managed technical zone” with tolls designated as “security taxes” and reparations earmarked for Iranian reconstruction. The AP confirmed that toll revenues are structurally allocated to reconstruction — which means Iran has built a fiscal dependency on the strait remaining partially closed. Oman’s Transport Minister publicly rejected this framing, telling Al Jazeera on April 9 that “no tolls can be imposed for crossing Hormuz,” but Oman’s objection has not changed the operational reality that the IRGC, not Oman, controls which ships transit.

Tasnim News Agency, Iran’s semi-official outlet, stated plainly that the strait “would not return to pre-war levels of travel” — a declaration that, if accurate, means the physical premium over futures is not a temporary dislocation but a structural feature of the post-ceasefire oil market.

What Happens to Asian Refiners Caught Between Physical and Paper?

The refiners who buy 60% of Saudi crude under term contracts are absorbing the most acute pain. Wood Mackenzie’s Sushant Gupta warned in March that “Asian refiners will struggle to fulfil crude buying requirements for April, leading to run cuts across the region” — and his worst-case scenario of 6 million bpd in crude run cuts across Asia is no longer a stress test but a description of current conditions. China faces 750,000 bpd in cuts, India 400,000, South Korea roughly 300,000. These are not voluntary conservation measures; they are the consequence of barrels that physically cannot reach refineries because the waterway they transit is controlled by a belligerent that charges admission.

For a Korean refiner that contracted to lift 200,000 bpd of Arab Light at the May OSP, the arithmetic is punishing from every angle. The refiner pays Aramco the OSP differential (+$19.50) over the Oman/Dubai average — but the Oman/Dubai benchmark itself was distorted when S&P Global Platts suspended nominations of crude loading inside Hormuz from the Dubai benchmark on March 2, reducing deliverable grades to Murban and Oman only. The benchmark the refiner is paying a premium over no longer represents the market the refiner is buying into. Meanwhile, the same refiner’s hedging book, built against ICE Brent futures, is underwater by the full $35 spread — the hedge was designed to offset price risk, not to absorb the collapse of the price-discovery mechanism itself.

Chevron CEO Mike Wirth captured the dynamic with precision: the “very real, physical impacts” of the Strait blockade “are rippling around the world” but “are not yet fully reflected in the oil futures price curve.” For refiners, this means the pain they are experiencing in procurement costs, delivery uncertainty, and basis risk is invisible to the financial instruments they use to manage that pain — a hedging crisis layered on top of a supply crisis.

“You are seeing it but the financial market is almost masking the true tightness that everywhere else is showing up. The futures price is almost giving a false sense of security that things are not that stressed.”

— Amrita Sen, Founder and Research Director, Energy Aspects, CNBC, April 8

The Ceasefire’s Price Signal — and What It Doesn’t Signal

The ceasefire that took nominal effect on April 8 was supposed to be the catalyst for spread compression. It was not. Dated Brent dropped from $144.42 to $124.68 on April 8 — a sharp move, but one that still left physical barrels $32 above futures. By April 10, dated Brent had rebounded to $131.97 while futures hovered near $97, widening the spread back to $35. The first non-Iranian oil product tanker crossed Hormuz only on April 10, alongside five dry cargo ships — six vessels total against a pre-war baseline of 138 per day. ADNOC CEO Sultan Al Jaber confirmed on April 9 that the strait is “still not open” because Iran is “restricting and conditioning traffic.”

The physical market priced the ceasefire accordingly: as a change in the diplomatic label attached to the same operational reality. Rystad Energy reduced its 2026 average Brent forecast from $97 to $87 per barrel, reflecting an assumption that flows eventually normalize — but “eventually” is carrying a great deal of weight in that sentence. JP Morgan warned that Brent could “overshoot toward $150/barrel” if the Hormuz closure extends into mid-May, and the physical market’s refusal to converge toward futures suggests that traders with actual cargoes to move share JP Morgan’s skepticism about the ceasefire timeline more than Goldman’s optimism.

The IRGC strike on the East-West Pipeline pumping station on April 8 — after the ceasefire’s nominal start — further eroded confidence that the ceasefire changes the supply calculus. The strike reduced pipeline throughput by roughly 700,000 bpd, cutting Yanbu’s effective loading capacity from approximately 4.5 million bpd to under 4 million against the pipeline’s 7 million bpd design capacity. Saudi Arabia’s bypass route, the one infrastructure corridor that allows exports to avoid Hormuz entirely, is now operating at barely half its theoretical throughput.

Russia’s $9 Billion April and the Geopolitical Arbitrage

There is a third beneficiary of the super-contango that rarely features in Gulf-focused coverage, and it is the one with the least interest in seeing the spread compress. Russia’s Urals crude hit $116.05 per barrel in April — a thirteen-year high — and Bloomberg reported that the conflict effectively doubled Russia’s April oil revenues to $9 billion. Russia does not export through Hormuz, its crude trades at a discount to Brent that has narrowed as alternatives to Gulf supply become scarce, and its customers — primarily China and India — are now paying premiums they would never have accepted before the strait closed.

The geopolitical arithmetic is straightforward. Every week that Hormuz remains functionally closed transfers revenue from Gulf producers to Russia — not through any deliberate mechanism, but through the simple physics of a market where the largest supply corridor is blocked and the second-largest non-OPEC producer faces no such constraint. Russia’s interest in a prolonged Hormuz disruption is so structurally obvious that it barely needs stating, and yet the OPEC+ framework requires Moscow and Riyadh to coordinate production policy as if their incentives were aligned. The +206,000 bpd voluntary output increase that OPEC+ announced for May is, as Al Jazeera described it, “largely symbolic” against 9.15 million bpd in actual production losses — but even that symbolic gesture benefits Russia disproportionately, since Russia can actually deliver its incremental barrels to market while Saudi Arabia’s sit behind a chokepoint controlled by Iran.

Can Aramco Survive the June OSP Negotiation Intact?

The June OSP announcement, expected around May 5, will be the most consequential pricing decision Aramco has made since the 2020 price war with Russia — and in some ways more difficult, because in 2020 the problem was a demand collapse that affected all producers equally, while in 2026 the problem is a bifurcated market that punishes Saudi Arabia specifically. Aramco must set a differential that accounts for a physical market above $130, a futures market below $100, a benchmark (Oman/Dubai) that no longer includes the grades it was designed to represent, and a customer base that absorbed $17-per-barrel increases in May and will resist anything that looks like a repeat.

If Aramco sets the June OSP to track physical reality — raising differentials further to capture the scarcity premium — it risks accelerating the run cuts that Wood Mackenzie warns could reach 6 million bpd across Asia. Refiners that cannot afford the oil simply stop buying, and Aramco’s term-contract architecture, the foundation of its revenue predictability, fractures under the strain. If Aramco holds or cuts the differential to ease refiner pain, it leaves billions on the table at precisely the moment when Saudi fiscal needs are most acute — and signals to the market that the OSP mechanism has become a subsidy rather than a pricing tool.

The May decision — leaving $20.50 per barrel on the table against Bloomberg’s expectations — was readable as strategic restraint: protecting long-term relationships with Asian buyers who will still be purchasing Saudi crude in 2035. But the June decision cannot be explained by the same logic if the spread persists, because restraint in a $35-spread environment does not protect relationships — it destroys Aramco’s price credibility. Term buyers who received May barrels at a $22 discount to physical will expect the same treatment in June, and if they do not receive it, they will point to May as evidence that Aramco’s pricing is arbitrary rather than market-reflective.

Saudi Fiscal Arithmetic at $97 Futures vs $132 Physical

The question of which price Saudi Arabia actually receives is not academic — it determines whether the kingdom runs a manageable deficit or an emergency one. Bloomberg Economics puts Saudi Arabia’s fiscal break-even at $94 per barrel; adjusted for PIF spending commitments, the break-even rises to $111, according to Goldman Sachs modelling that projects an $80-90 billion deficit against the official $44 billion estimate. If Aramco’s realized price tracks the futures curve — which its hedging book and forward commitments partially link it to — the kingdom is selling oil at or near fiscal break-even while the physical market screams that every barrel is worth $35 more.

The East-West Pipeline bypass does not solve this equation; it merely narrows the deficit. Yanbu’s loading capacity of roughly 4.0-4.5 million bpd — reduced further by the April 8 pumping-station strike — covers approximately 60% of Saudi Arabia’s pre-war 7.3 million bpd exports. The remaining 40% either does not move or moves through Hormuz at the IRGC’s discretion, which in practice means it mostly does not move. Sadara’s $3.7 billion debt cliff on June 15 looms against this backdrop, as does the $71-billion-to-$30-billion contraction in PIF construction commitments that the fund’s 2026-2030 strategy document confirmed.

There is an additional fiscal dimension that Saudi planners will be modelling quietly: the December 2026 futures price of $79.92 implies the market expects this crisis to resolve into a price environment below Saudi fiscal break-even. If the forward curve is correct — and it is betting on Hormuz reopening, ceasefire holding, and demand destruction from run cuts persisting — then the windfall revenues Saudi Arabia should be earning from $132 physical oil are not materializing because the barrels cannot reach market, and the post-crisis price environment will be worse than the pre-crisis one because of the demand that was permanently destroyed during the closure.

What the Spread Is Actually Telling Us

Strip away the technical language and the super-contango reduces to a single proposition: the oil market believes that the ceasefire will eventually work but that it has not worked yet, and every day it does not work costs the global economy billions in misallocated capital, stranded refining capacity, and pricing distortions that will take months to unwind. The $35 spread is the market’s confidence interval around the word “eventually” — the wider it is, the less the market trusts the ceasefire timeline, and at $35 it trusts it very little.

For Saudi Arabia, the spread is a particularly cruel metric because the kingdom needs both halves of the market to resolve in its favour. It needs physical prices to remain elevated so that the barrels it can export through Yanbu generate maximum revenue. But it also needs futures to recover so that its term-contract architecture — the system on which Aramco’s entire commercial model depends — prices in line with realized sales rather than forward expectations of normalization that may not arrive on schedule. These two needs are mathematically opposed: physical prices stay high only if Hormuz stays disrupted, and futures recover only if the market believes Hormuz is reopening.

The spread also measures something that no one in Riyadh, Washington, or Tehran is eager to quantify publicly: the ceasefire’s credibility, priced in dollars per barrel. When ADNOC’s Al Jaber says the strait is “still not open” and Tasnim says it “would not return to pre-war levels of travel,” the physical market listens. When Goldman models a thirty-day recovery and Rystad cuts its 2026 forecast to $87 average, the futures market listens. The $35 gap between those audiences is the distance between what is happening on the water and what diplomats are promising in conference rooms — and until the tankers start moving, the water wins.

The scenario where Hormuz remains effectively closed into mid-May — the same one JP Morgan warned could push Brent to overshoot $150 — carries a harder endpoint. In that world, the super-contango doesn’t compress. It widens, physical scarcity intensifies, the Bab el-Mandeb second chokepoint faces its own pressure, and the June OSP negotiation becomes not a pricing exercise but a crisis-management conversation between Aramco and the Asian refiners who keep the lights on across the Pacific Rim.

“In our view, US$200/bbl is not outside the realms of possibility in 2026.”

— Sushant Gupta, Research Director, Asia Pacific Refining, Wood Mackenzie

FAQ

Why can’t arbitrageurs close the $35 spread between dated Brent and futures?

Classical arbitrage requires buying the cheap instrument and delivering against the expensive one. In this case, a trader would need to buy a futures contract at $97 and deliver physical oil at $132 — but delivering physical oil requires a cargo, and cargoes cannot transit Hormuz. The spread persists because the physical supply is geographically stranded behind a chokepoint that the IRGC controls, making the arbitrage mechanically impossible regardless of how much capital is available to execute it. S&P Global Platts has not recorded an EFP above $5 in its 39-year assessment history prior to this crisis; the normal range is $0.50-$2.00.

How does the Oman/Dubai benchmark distortion affect Asian buyers specifically?

When S&P Global Platts suspended nominations of crude loading inside Hormuz from the Dubai benchmark on March 2, it reduced deliverable grades to Murban and Oman — both of which load outside the Strait. This means the benchmark that Aramco’s Asian OSP is calculated against no longer includes the Gulf crudes it was designed to represent, creating a basis mismatch that Asian buyers cannot hedge. A South Korean refiner lifting Arab Light is paying a differential over a benchmark that reflects Abu Dhabi and Oman supply conditions, not the Saudi or Iraqi supply conditions that historically anchored the assessment — a structural mispricing that will persist until Hormuz nominations resume.

What is the IRGC’s financial incentive to keep Hormuz partially rather than fully closed?

Full closure generates zero toll revenue and maximises international pressure for military intervention. Partial closure — the current model — generates approximately $20 million per week in VLCC tolls, allows Iran’s own Kharg Island exports ($3.5 billion and counting) to continue under IRGC escort, and maintains the physical scarcity that keeps dated Brent above $130 (inflating the value of every Iranian barrel sold). The Hormuz Management Plan passed by Iran’s parliament on March 31 formally allocates toll revenues to reconstruction, creating a domestic fiscal constituency for the strait remaining a managed chokepoint rather than an open waterway. Full reopening eliminates all three revenue streams simultaneously.

Could Aramco switch from Oman/Dubai to dated Brent as its Asian pricing benchmark?

Technically possible but commercially catastrophic in the current environment. Switching to dated Brent would immediately reprice all Asian term contracts $35 higher per barrel — the full width of the super-contango — which would trigger mass contract rejections and accelerate the refinery run cuts that are already at 6 million bpd potential across Asia (Wood Mackenzie). Aramco’s benchmark choice is also a geopolitical signal: Oman/Dubai anchors pricing to the Gulf, reinforcing Saudi Arabia’s centrality in Asian crude markets, while dated Brent anchors pricing to the North Sea, effectively ceding benchmark sovereignty to a European assessment. No benchmark switch has been announced or is expected during the crisis period.

What happens if the spread is still $30+ when the June OSP is announced around May 5?

Aramco faces a trilemma with no clean exit. Raising the differential to track physical reality prices out the Asian refiners whose demand Aramco needs post-crisis. Holding the differential at May levels signals that the OSP is a political instrument rather than a market-reflective pricing tool, undermining decades of pricing credibility. Cutting the differential to track futures acknowledges that Aramco is effectively selling at a discount to physical at a moment of extreme scarcity, which is defensible as relationship preservation but toxic to near-term revenue. Industry sources expect Aramco to hold or modestly increase the differential while privately extending credit terms and cargo-deferral options to its largest Asian buyers — a solution that defers the revenue hit into Q3 rather than resolving it.