The White House is reportedly considering a 90-day ban on US diesel exports, in an effort to bring down record diesel prices ahead of the midterms. The policy proposal, while disruptive to oil markets, is also likely to fail on the merits and result in higher prices for refined products.
The logic of a ban is simple: Keep more diesel at home, and prices should fall. But US refiners and international buyers have spent years building export-based supply chains. Restricting those flows would create two problems: excess diesel supply on the US Gulf Coast, and tighter supply across some of the largest US diesel markets in Latin America.
US distillate exports averaged ~1.56 MMb/d over the four weeks ending Sept. 18, equivalent to 30% of US distillate production. Roughly 90% of exports leave from the Gulf Coast.
Central and South America economies would take the most direct hit from a diesel export ban. East Daley Analytics’ analysis of Vortexa vessel data shows South America accounted for ~128 Mb/d, or 41%, of tracked US diesel exports YTD in 2026. Add Central America and Mexico, and the regional exposure rises to ~216 Mb/d, or 68% of tracked volumes. Ecuador stands out as the largest export destination at roughly 56 Mb/d, followed by Chile at 29 Mb/d and Honduras at 24 Mb/d.
A diesel export restriction would force these buyers to compete for replacement barrels from Europe, the Middle East and other suppliers. The result would likely be a geographic disconnect: lower diesel prices initially on the US Gulf Coast, but higher prices in markets that depend on US supply.
Export Ban Pushes Pump Prices Higher
For US refiners, the first response to a ban would be optimization. Refiners can shift yields away from diesel and toward gasoline, jet fuel and naphtha, but that flexibility has limits. If exports remain restricted, diesel inventories would build, Gulf Coast diesel cracks weaken, and physical constraints eventually force refiners to reduce crude runs.
Here is where the impacts expand beyond diesel, and in counterproductive ways for the White House. Lower refinery utilization means less production of gasoline, jet fuel and naphtha. Restricting the diesel trade would lower supplies of other refined products, supporting higher prices at the pump and for airline travel.
A US export ban would increase international diesel prices, and likely push up global crude benchmarks like Brent as well. Since the US and global oil markets are otherwise interconnected, WTI could rise in sympathy with higher international prices, even as physical demand from refiners weakened.
For naphtha, volumes could initially increase as a percentage of refinery yield as refiners optimize away from middle distillates, but production would eventually decline as less crude is processed. Stronger diesel cracks would incentivize refiners to maximize middle distillate production, potentially reducing naphtha yields. The longer an export restriction lasts, the greater the risk of tightening naphtha supply, both domestically and internationally.
The disruption would also move downstream into Gulf Coast export infrastructure. East Daley’s Vortexa data shows some of the largest diesel export volumes moving through terminals associated with Phillips 66 (PSX), Chevron (CVX), ONEOK (OKE), Marathon (MPC), MPLX and ExxonMobil (XOM). The largest locations include PSX’s Clifton Ridge at roughly 34 Mb/d YTD, Chevron Pascagoula at 24 Mb/d, and Galena Park at 22 Mb/d.
These facilities would face direct downside risk to marine throughput under a full export ban, although the magnitude depends heavily on policy design. A partial restriction or exemptions for major regional buyers would materially reduce the barrels at risk.
How Long Can the Industry Take the Hit?
The biggest question of a diesel export ban is: How long can refiners absorb the backlog of stranded product before it becomes a refinery utilization problem? Historical storage data offers some clues.
US distillate stocks right now are at an historically low level, totaling 107.4 MMbbl for the week ending Sept. 18, according to Energy Information Administration (EIA) data. The last big oil demand shock occurred during the Covid-19 lockdowns in 2020-21. US distillate stocks climbed rapidly in 2020 when travel shut down, reaching as high as 178 MMbbl that summer (see figure at right). Using this level as an upper bound for storage, refiners and marketers could absorb the lost diesel exports for about 45 days, or half the span of a 90-day ban.
Terminal volumes would fall immediately under an export ban, and the knock-on effects become more disruptive once diesel storage fills. Refinery runs then slow, and supplies of refined products across the barrel tighten, creating more price volatility for consumers. – Julian Renton and Keland Rumsey Tickers: CVX, PSX, MPC, MPLX, OKE, XOM.
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Rising US LNG feedgas demand has the potential to float all boats — but only if crude oil and NGL markets can support the growth.
Reaching nearly 26 Bcf/d of LNG feedgas demand by the end of 2027 will require producers to drill aggressively across the Permian, Haynesville and Northeast. In the Permian especially, that growth depends on steadier crude prices, to give producers the confidence to commit capital, subscribe to new pipeline capacity and fill the infrastructure midstream companies must build.
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LNG demand may be the rising tide — but crude and NGL markets will determine whether all boats can rise with it.
Join East Daley Analytics today, Sept. 30 at 10:00 am MT for a discussion at the intersection of energy. Click here to join us!
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