America Has the Oil. Why Is Diesel Still So Expensive?

Heavy crude is piling up in the Americas while diesel inventories sit well below normal. Refiners' heavy-oil units are running near their limits, freight costs have surged, and attacks on shipping now threaten the routes that bypass Hormuz.

The Energy Information Administration forecasts US crude production of 13.9 million barrels per day in 2026. Yet the national average retail diesel price was $6.28 a gallon on 13 October, against $4.34 for regular gasoline, according to AAA. Diesel costs $1.94 a gallon more than gasoline. Federal Reserve Bank of Dallas economists note that retail diesel has never before exceeded gasoline by so much. Diesel is about 25 cents below its record of $6.53 on 22 September, but it remains far above any pre-2026 level.

Two numbers explain most of the problem. In the week ended 2 October, US commercial crude stocks were 1% above their five-year average for the time of year, while distillate stocks were about 12% below. The United States has an adequate supply of crude but too little diesel.

Crude production, refining capacity, finished-fuel stocks and shipping capacity are separate parts of the supply system. This week's evidence suggests the binding constraint is turning crude into diesel and moving it to where it is needed, not how much crude exists.

The US fuel position

The EIA figures are the latest official weekly readings. Because of the Columbus Day holiday, the next Weekly Petroleum Status Report is due on Thursday, 15 October. The crack-spread figure is an intraday reading from 9 October, not a measurement for 14 October.

Sources: AAA fuel prices, EIA weekly petroleum report, EIA October outlook, Reuters — EIA weekly, 7 October, Oil & Gas 360 — EIA five-year comparisons, Reuters — SPR, 5 October, Reuters market report, S&P Global — ULSD crack, Dallas Fed.

1. A refining shock on top of an oil shock

Dallas Fed economists, in research published on 8 October, estimate that 6–8 million barrels per day of global refining capacity has been curtailed since late spring. That is up to a tenth of the world total. The causes are damaged Middle East facilities, Ukrainian drone strikes on Russian refineries, shipping restrictions and reduced Chinese processing. The authors estimate Russian refining capacity fell by as much as 60% over the summer, while noting that estimates vary widely from month to month. The figure describes capacity affected or unavailable, not permanent losses.

As a result, wholesale diesel prices have risen much faster than crude. The Dallas Fed finds refining margins ("crack spreads") above the levels reached after Russia's invasion of Ukraine in 2022, and attributes this to supply constraints rather than retailer markups. European importers have also turned increasingly to US distillate, so American buyers are competing with Europe for the same barrels.

US refinery utilisation has fallen from 98% in late August to 92.7%. Utilisation normally eases in autumn as plants go into maintenance. Total crude-distillation capacity is not the only limit. Coking units, which process the heaviest fractions of crude, were already running near maximum (see section 2), and that caps how much additional heavy crude refiners can take. Diesel output depends on further capabilities: hydrocracking and hydrotreating capacity, hydrogen supply and suitable feedstocks. Releasing crude from storage cannot replace any of these, and it cannot replace finished diesel.

Extra barrels of crude can feed a refinery, but they do not add refinery throughput overnight.

Source: Dallas Fed — Refinery outages pumping up fuel prices more than cost of crude oil.

2. Heavy crude is piling up in the Americas while overseas buyers go short

Heavy crude from Canada, Venezuela, Colombia and Ecuador is struggling to reach export markets, even as refiners in Europe and Asia look for alternative supplies.

Reuters reported on 12 October that shipping crude on a supertanker from the Americas to Asia now costs more than $80 million, or about $40 a barrel, compared with around $10–15 million near the start of the year. A US Gulf Coast-to-Europe supertanker cargo costs about $46 million, or roughly $24.50 a barrel, including ship-to-ship transfer costs.

As a result, certain Canadian, Colombian and Ecuadorian heavy grades have fallen by more than $10 a barrel in six weeks, even with international benchmarks above $100.

High freight costs also help explain the $11.61 gap between Brent and WTI. Goldman Sachs cites expensive US–Europe shipping as a reason WTI is trading unusually low against Brent. Freight is one contributor, not the only one: relative inventory positions and the regional pattern of supply disruptions also affect the spread. But the direction is consistent with the rest of the evidence. American crude is cheap at home partly because it has become expensive to move abroad.

US refiners are not absorbing all the discounted heavy barrels because the coking units those grades require are close to capacity. According to analysts cited by Reuters, Venezuelan crude and heavy barrels released from the Strategic Petroleum Reserve had already pushed US coker utilisation close to maximum, and high freight is now forcing heavy sour crude into storage. A refinery that can run one heavy grade does not necessarily have room to run them all.

The result is a regional surplus of some crude grades alongside a shortage of finished fuel. It is not evidence that the United States has too much diesel.

Sources: Reuters — Americas have glut of heavy oil due to freight squeeze (syndicated copy); Reuters — Goldman on Brent–WTI, 12 October.

3. The bypass routes are now inside the danger zone

The Financial Times, using UK Maritime Trade Operations records and European security sources, counted 24 vessels attacked in the two weeks to 11 October. That is the highest two-week total since the war began, and six of those attacks came on 11 October alone. The FT also cited Kpler data showing 2.9 million barrels of oil transiting the Strait of Hormuz on 11 October, the lowest single day this month, with the seven-day average about 43% below pre-conflict levels. Kpler cautioned that both figures may be revised upward as satellite tracking picks up more vessels.

The 2.9 million figure is one day's transit. It does not represent a sustained export rate.

Earlier Kpler data, reported by Reuters on 8 October, measured something different. Over the preceding week, crude crossing the strait fell 27% from a wartime high, to at least 10.1 million b/d. Exports from the Gulf of Oman coast and the Red Sea rose to 6.7 million b/d, more than double pre-war levels. Those figures cover an earlier week, count crude only, and exclude tankers sailing with transponders off. The 6.7 million b/d figure also measures something else again: exports from terminals outside the strait, not traffic through it.

These are three different measurements:

• a single day's oil transits through the strait,
• a weekly count of crude crossing it,
• regional export volumes that bypass it.

They are not interchangeable. Read together, they show that bypass terminals have been offsetting much of the Hormuz shortfall: principally Fujairah and Omani ports on the Gulf of Oman, and Yanbu on the Red Sea.

That is why this week's change in Iranian tactics matters. In a Reuters report published on 14 October, two senior Iranian officials said a revised campaign aims to raise the pace of attacks and extend the risk area into the Gulf of Oman and beyond. They linked the strategy to keeping oil prices high before the US midterm elections. These are statements of intent, not measured effects.

The geography is the concern. Fujairah lies on the Gulf of Oman, outside the strait. An attack zone that extends past Hormuz reaches the main bypass terminal. The port has been hit before: drone attacks in March halted exports there.

There is a counterpoint. A US military official told Reuters that after US strikes destroyed much of Iran's radar capability, Iranian forces began using unarmed spotters in small boats. The same official said Iran had been unable to prevent exports through the strait from rising, because it was unwilling to risk its remaining fast boats. The Joint Maritime Information Center logged 10 incidents in the strait between 1 and 8 October.

The key question for the coming week is whether bypass volumes hold, not only whether Hormuz flows recover. If both fall at once, the market's ability to offset the lost barrels would shrink sharply.

Sources: Reuters — Iran shifting tactics (syndicated copy); Financial Times — Hormuz vessel attacks; Sourcing Journal — FT and Kpler figures; Reuters — Kpler weekly data, 8 October; Maritime Executive — JMIC data; Trading Economics — Fujairah attacks, March.

4. Saudi output is recovering but remains about 2 million b/d short

In OPEC's monthly report published on 13 October, Saudi Arabia reported directly to OPEC that it produced 8.372 million b/d of crude in September. That is up more than 2 million b/d from August, when output had fallen to its lowest level in more than three decades. This is Riyadh's own figure. OPEC also publishes separate estimates compiled from outside "secondary sources", and after attacks the two series can diverge. We have not used a secondary-source estimate for Saudi Arabia here.

Saudi Arabia's required production under the OPEC+ arrangement is 10.478 million b/d for September, a level held unchanged for October. September output was therefore about 2.1 million b/d below that level. Required production is a quota ceiling, not a measure of capacity, but the gap shows that the recovery is real and incomplete.

Production also does not tell you how much was exported, or by which route. Production, pipeline throughput, tanker loadings and delivered exports are four separate measurements. Reuters reports that Aramco increased loadings from its Gulf export terminals in September after an attack on the East–West pipeline disrupted shipments via the Red Sea. If that pattern continued, much of September's recovery shipped through Hormuz, the route now facing the heaviest attacks of the war. Current throughput on the East–West line has not been independently verified.

The security picture also worsened this week. On 14 October, Saudi Arabia's Energy Ministry said an administrative building belonging to Aramco in Dhahran had been attacked late on 13 October, causing a limited fire with no injuries or deaths.

• Damage: A company source told Reuters that a ballistic missile struck the headquarters complex and damaged the top three floors of an office tower.
• Intercepted missile: The Saudi-led coalition said fragments of a missile it intercepted over Dhahran fell on a residential area.
• Attribution: The Houthis had threatened to target Aramco's Dhahran headquarters in retaliation for Saudi-led strikes on Sanaa, and Saudi authorities attributed missiles intercepted over Riyadh the same night to the Houthis. We have not seen a confirmed Houthi claim for the Dhahran strike itself.
• Operations: The ministry gave no details of any operational impact, and no loss of production or exports has been verified.

The attack followed the Houthi-claimed strike on Riyadh's international airport on 10 October, which killed 13 people.

The evidence to watch is Gulf and Yanbu loadings, Saudi stock changes and confirmed deliveries, not production targets.

Sources: Reuters — OPEC September output (syndicated copy); Bloomberg via Rigzone — Saudi direct communication; OPEC+ required production; Reuters via Al-Monitor — Aramco building attack; Gulf Business — Dhahran; France 24 — Houthi missile attacks; Reuters via Egypt Oil & Gas — Riyadh airport strike.

5. Russian diesel: the volumes are announced, not delivered

Washington is working on the diesel problem over two time horizons.

Now: Russian diesel. On 9 October, President Trump announced a diesel supply arrangement with President Putin, set out in four tranches. Russia's government confirmed it was willing to supply oil and petroleum products to US and global markets. It did not confirm the 4.8-million-tonne total or any delivery schedule.

* US distillate product supplied, four-week average: 3.8 million b/d (EIA, week ended 2 October). Conversions use 7.45 barrels per tonne.

The first three tranches total 1.8 million tonnes, about 13.4 million barrels or roughly 3.5 days of US distillate demand. The remaining 3 million tonnes depends on the condition of Russian refineries, which have been the main target of Ukraine's drone campaign. Goldman Sachs estimates Russian refinery outages are about 3 million b/d higher than a year ago. Russia has also banned diesel exports by producers since July, and on 30 September extended the ban to the end of October. It has not said how the announced tranches fit with that ban.

The US legal position has three separate layers:

• Sanctions licence: The Treasury issued General License 135 on 9 October. It authorises transactions related to the sale, delivery, offloading and import of Russian-origin diesel, explicitly including into the United States, until 7 April 2027. It does not permit debits to US accounts of Russia's central bank, National Wealth Fund or Ministry of Finance.
• Statutory ban: GL 135 is a sanctions authorisation, not a change in law. The Ending Importation of Russian Oil Act of 2022 remains in force, and Ship & Bunker reports that the licence is being treated as a temporary executive waiver. The legal interaction for US imports has not been publicly settled.
• European sanctions: EU and UK sanctions on Russian products remain fully in force.

On 13 October, Trump said the diesel was intended for the wider world market rather than mainly for US consumption, although the licence permits both. Lawmakers from both parties have objected.

The market reacted to the announcement itself, not to any cargo: the NYMEX ULSD crack fell $6.45 on 9 October. The relevant test is whether identified cargoes are loaded and discharged. We have found no confirmed loadings or deliveries under the arrangement.

The energy ceasefire. On 11 October, Trump announced an immediate "energy ceasefire" between Russia and Ukraine, saying both sides had agreed. Implementation is disputed:

• Moscow has not publicly confirmed the ceasefire.
• President Zelenskyy said Ukraine held off strikes on Russian energy facilities overnight on 11–12 October, but that Russia struck Ukrainian energy sites, including a power plant in Kharkiv, after the announcement.
• As of 13 October, monitors had reported no new Ukrainian strikes on Russian refineries since the announcement.
• A similar announcement in September did not hold.

Even if strikes on refineries have paused, there is no evidence yet that damaged Russian capacity has come back. Repair timelines are unknown.

Later: Texas refining. Vice President JD Vance announced that the administration will use the Defense Production Act to support an expansion at Delek's 74,000 b/d Tyler, Texas, refinery. The act has never been used to add refining capacity, although an April presidential determination cleared the way. No added capacity, budget or completion date has been given, so the project cannot be counted as near-term supply.

The test for both measures is how many barrels of finished diesel actually arrive. So far, the arrangement consists of a sanctions licence and announced tonnages.

Sources: OFAC — General License 135; Ship & Bunker — GL 135 and the 2022 Act; CNBC — tranche volumes and Goldman estimate; The Hill — Trump's announcement; S&P Global — Russian confirmation, export ban and crack move; Reuters — Russian diesel deal; Axios — ceasefire status; AP via PBS — Zelenskyy on continued Russian strikes; Euromaidan Press — refinery strike monitoring; Reuters — Delek Tyler expansion.

6. The US Gulf is recovering from Hurricane Isaias

The Marine Minerals Administration, formed in July by reuniting BOEM and BSEE, estimated that operators had shut in 71.51% of Gulf offshore oil production, or 1.46 million b/d, on 9 October as Hurricane Isaias approached. By 13 October that share had fallen to 16.13%, or 329,000 b/d still offline. (The agency now refers to the Gulf of Mexico as the Gulf of America.)

That is a large recovery in offshore output. The figures are operator-reported shut-in estimates. They do not cover the recovery of refineries, ports or pipelines along the coast.

Sources: Marine Minerals Administration — 9 October and 13 October update.

Elsewhere in the Americas

Guyana: oil or gas. Sources close to negotiations told Reuters that the ExxonMobil-led consortium expects to need around 2 billion cubic feet of gas per day for reinjection to meet its crude targets. A proposed 6-million-tonne-a-year LNG project could therefore start at 3 million tonnes, or exports could be deferred, and fertiliser projects could slip. No decision has been announced. Reuters

US biofuels. On 13 October the EPA proposed reallocating all of the 770 million renewable identification numbers (RINs) by which 2025 small-refinery exemptions exceeded its projections. One option splits the volume equally between 2026 and 2027; the other puts it all in 2027. Comments close on 4 December. The proposal affects future compliance costs, not near-term diesel output. EPA; Reuters

A Caspian allegation. A 12 October OilPrice.com investigation alleges that discounted Iranian crude is being moved across the Caspian and blended into Russian export streams. Part of its argument treats rising Caspian Pipeline Consortium throughput as unexplained, but KazMunayGas attributes that growth to the Tengiz expansion. We have not verified any onward sales to US buyers, and this remains an allegation to follow. OilPrice.com; KazMunayGas

What we are watching next

• EIA, Thursday 15 October: whether distillate stocks close any of the 12% gap to the five-year average, and how refinery runs move as maintenance ends.
• Hormuz and the bypass routes: revisions to Kpler's 11 October figure, and Fujairah and Yanbu loadings, which now matter as much as transits through the strait.
• Russian diesel: the first identified cargoes loaded and discharged under GL 135, Russia's export-ban decision at the end of October, and whether either side confirms the energy ceasefire.
• Saudi Arabia: export-terminal loadings against stock changes, and any independent reading of East–West pipeline throughput.
• Freight: whether supertanker rates ease enough to reopen the Americas-to-Asia trade for heavy crude.
• Gulf of America: the remaining ~329,000 b/d of offshore shut-ins.

Where we stand

The United States has a large crude-producing system and sophisticated refineries. What it lacks is unlimited capacity to turn every available barrel into the fuel needed, where and when it is needed.

US crude stocks sit near normal levels while distillate stocks are well below them. Heavy crude is stranded by freight costs, refiners have little room to process it, and the routes that carry Gulf oil around Hormuz are now within reach of attack. The Russian arrangement so far consists of a sanctions licence and announced tonnages, with no confirmed deliveries. The first announced tranche, if delivered, would equal about half a day of US distillate demand.

The question is no longer simply whether there is enough oil. It is whether that oil can be refined, shipped and delivered as usable fuel before the next disruption.

Data note: All figures reflect the cited release dates. Production, pipeline throughput, loadings and deliveries are reported separately. Single-day observations are not treated as sustained rates. Official claims, announced volumes, stated intentions and unverified trade routes are not treated as realised supply changes. Tonne-to-barrel conversions use 7.45 bbl/t, and days of demand are calculated against US distillate product supplied of 3.8 million b/d.