By Kal Sharven

TL;DR: Diesel hit a national average of $6.53/gallon this week, up from $3.69 a year ago, as the Iran war and the Russia-Ukraine conflict choked Middle Eastern and Russian refined-product supply. On Tuesday, President Trump and Treasury Secretary Scott Bessent floated banning US diesel exports to bring the price down. By Wednesday the White House had backed off, after Energy Secretary Chris Wright, the American Petroleum Institute, GasBuddy, and the Chamber of Commerce all made the same point: refineries can’t produce diesel in isolation. A barrel of crude becomes gasoline, diesel, and jet fuel together, in something close to fixed proportions, and US refiners are already running at 97.8% of capacity — there’s no slack to make more of everything. Cutting diesel exports doesn’t free up diesel for the domestic market; it just cuts total refinery runs, taking gasoline and jet fuel down with it. The Gulf Coast, which supplies over 90% of US distillate exports, is also structurally disconnected from the Midwest farm belt that’s supposedly being protected — Iowa’s diesel comes from regional refineries and pipelines fed by Oklahoma, Kansas, Minnesota, and Wisconsin, not the Gulf. A more coherent lever is raising the ethanol blend rate from E10 to E15, which doesn’t require more crude throughput at all — it just changes how much of the gasoline pool has to be refined from petroleum in the first place. That mechanism is real, and Washington is already leaning on it (EPA issued an emergency nationwide E15 waiver back in March, and a permanent year-round E15 bill is sitting in the Senate). But it has a ceiling nobody pushing it seems to mention: converting the entire US gasoline pool to E15 would require about 1.75 billion more gallons of ethanol a year than the country currently has the capacity to produce.

The week this happened

Diesel prices have been climbing all year, but the acute spike is recent: from about $3.69/gallon a year ago to $6.5276/gallon this week, with roughly a dollar of that increase coming in the last month alone. The proximate cause is geopolitical, not domestic — the US-Iran war has disrupted shipping through the Strait of Hormuz and Bab el-Mandeb, and the Russia-Ukraine war continues to squeeze Russian refined-product exports, tightening the global diesel market that US barrels increasingly serve.

On Tuesday, September 22, Trump and Bessent signaled openness to restricting US diesel exports, with Bessent describing it as a feasibility review — “examining whether it’s feasible… whether a full or partial ban would work.” Politico reported, citing unnamed sources, that the administration was preparing a possible 90-day export ban. By Wednesday, the White House had denied pursuing a formal ban, and Wright reframed the goal instead as finding “the most efficient way to get more diesel into the United States of America, and continue maximum flows of gasoline and jet fuel” — implicitly conceding that a ban would threaten exactly the gasoline and jet fuel supply it wasn’t meant to touch. The Chamber of Commerce and Business Roundtable sent a joint letter opposing the idea; API called it something that “would only compound the problem.”

Why a refinery can’t give you diesel without gasoline

The core objection, made almost identically by Wright, GasBuddy’s Patrick De Haan, and Rapidan Energy’s Bob McNally, is a refining-technology fact rather than a policy opinion: distillation splits one barrel of crude into a slate of products at once. The American Fuel & Petrochemical Manufacturers — the US refiners’ own trade association — puts it plainly: refiners can shift yield among gasoline, diesel, and jet fuel in response to market signals, but that shifting is bounded by refinery configuration, crude input grades, and “the high costs of modifying refinery infrastructure,” with real transformation costs and minimum lead times attached, and “most operators have already captured the easiest gains.” On the secondary conversion units that do most of that shifting, industry technical literature on hydrocrackers puts the typical usable conversion-rate adjustment at roughly 10-20% before other constraints — heater limits, fractionation capacity, catalyst behavior — bind. Refiners are, in fact, leaning on that flexibility right now: EIA data show jet fuel took a record share of US refinery output in 2024 as refiners shifted barrels toward it, evidence the slate does move — just not freely, and not on short notice.

The direction of that shift is visible in EIA’s own refinery yield data. The average US barrel yielded 47.8% finished motor gasoline in 2021; by 2025 that had fallen to 45.9%. Over the same years, the distillate yield rose from 29.7% to 30.0%, essentially flat but part of a longer upward drift. Refiners have already been quietly reallocating yield toward diesel as diesel cracks have widened — which is the strongest evidence the yield ratio isn’t rigid. It’s also evidence of how small the annual movement is: two percentage points of gasoline yield over four years, not a switch refiners can throw overnight.

What makes this bind acutely right now is capacity, not just proportions. US refinery utilization hit 97.8% in the first week of September — among the highest rates in years. At that level there’s essentially no idle crude-processing capacity to absorb a policy shock. If exports of one product are restricted and a refiner’s realized revenue on that barrel drops, the textbook response — confirmed by both Wright and De Haan this week — is to run less crude, not to somehow produce the same diesel and just keep it domestic. Less crude run means less of everything: less diesel, less gasoline, less jet fuel. An export ban aimed narrowly at diesel prices arrives instead as a broad-based fuel-supply shock.

The Gulf Coast doesn’t reach Iowa the way you’d think

This is the part of the story that gets lost in a Washington debate framed around “US refiners” as a single entity. Refining and export capacity for diesel are heavily concentrated on the Gulf Coast, and the Gulf Coast is not where Midwestern diesel comes from.

On EIA’s own numbers, the arithmetic is stark. Gulf Coast (PADD 3) refiners exported 1,127 thousand barrels per day of distillate fuel oil in 2025. Total US distillate exports that year averaged roughly 1,250 thousand barrels per day. That puts the Gulf Coast’s share of all US diesel exports at just over 90%. Diesel exports, in other words, are close to a single-region phenomenon.

The Midwest (PADD 2) — where Iowa sits — has spent the last decade building the opposite kind of independence. EIA analysis of the region found in-region refineries covering 84% of the Midwest’s own fuel needs by 2015, with regional refining capacity growing roughly 500,000 barrels per day (14%) against consumption growth of only about 200,000 barrels per day (4%) since 2010 — a gap that has kept widening since. As of June 2026, Midwest refineries were running at 100.6% of nameplate operable capacity, on 4.28 million barrels per day of capacity — a region running as hard as the Gulf Coast, on its own account, largely independent of it.

The pipeline geography backs this up directly. Iowa’s diesel moves mainly through the Magellan Pipeline system, which EIA analysis describes as fed “mostly by refineries in Oklahoma, Kansas, Minnesota, and Wisconsin” — not the Gulf Coast. Regional refineries like Flint Hills’ Pine Bend plant in Minnesota (392,000 barrels/day, supplying more than half of that state’s own gasoline and diesel) and Phillips 66’s Wood River refinery in Illinois (173,000 barrels/day, including 70,000 barrels/day of distillate) are the actual local supply base. The one pipeline that does run Gulf Coast crude oil products north — Explorer Pipeline, from Port Arthur, Texas to Hammond, Indiana — terminates near Chicago, at the eastern edge of the Midwest, and connects into the Magellan system at only a single point in Glenpool, Oklahoma, making it a minor, secondary contributor to Magellan’s own regional supply rather than its backbone.

Put together: even in the scenario the export-ban proponents imagine — a Gulf Coast diesel glut, as barrels that would have gone to Mexico or Europe pile up with nowhere to go — that surplus doesn’t have an efficient path into Iowa. It isn’t a matter of the “pipelines shutting down” in a literal sense; there’s no evidence of that specific mechanism in what’s been reported. But the region has neither the pipeline capacity nor, per the refiners’ own stated reaction to lost export revenue, the incentive to simply reroute that volume north. The documented response to a export-driven revenue hit is refiners cutting runs, not rerouting barrels a thousand miles inland through a pipeline network that wasn’t built for that flow. A ban aimed at helping Midwestern farmers and truckers would primarily disrupt a market — Gulf Coast exports — that Midwestern diesel prices were never structurally tied to in the first place.

What a ban would put at risk, precisely

It’s worth being specific about what “restricting exports” would actually restrict, because the exposed volumes are concrete. Mexico was the single largest destination for US distillate fuel oil in June 2026, taking 288,000 barrels per day out of 1,432,000 barrels per day in total US distillate exports that month — about a fifth of everything the US shipped. Mexico’s own diesel production has been rising sharply: national output climbed from roughly 162,000 to 280,700 barrels per day between November 2024 and November 2025, as Pemex’s national refining system crossed 1 million barrels per day of crude processing for the first time since 2015, and its long-delayed Olmeca refinery at Dos Bocas posted a record 252,000 barrels per day of fuel output in July 2026 — still only about 74% of its 340,000-barrel-per-day design capacity. Even with that ramp-up, Mexico’s own energy ministry (Sener) puts combined national gasoline-and-diesel demand at roughly 1.3 million barrels per day in 2026, leaving real, continuing room for imports to fill the gap. Europe is a smaller but real outlet: EIA’s destination data for June 2026 shows the Netherlands alone taking 143,000 barrels per day, with the UK, France, and Spain adding smaller volumes on top, as European buyers — themselves short of refining capacity and increasingly shut out of Russian and Middle Eastern barrels — have pulled US distillate east.

None of this is a case that US export customers deserve protection over US drivers. It’s a case that these are real, committed flows into markets that would either go unserved or bid the same tight global barrel away from someone else, and that abruptly withdrawing US supply doesn’t concentrate more diesel at the US pump — it mostly reshuffles who’s short.

Where E15 actually fits — and where it runs out of road

This is the more interesting policy lever, and it works through a completely different mechanism than an export ban. E15 doesn’t ask refiners to produce more diesel at all. It changes the composition of the gasoline pool that gets sold at the pump, so that a smaller share of each gallon has to be refined from petroleum in the first place — freeing refiners to lean their fixed, near-maximum crude runs further toward distillate without a resulting gasoline shortage. It attacks the actual constraint (a fixed barrel split at max utilization) instead of trying to legislate around it.

The numbers show both why this works and how far it can go. US finished motor gasoline demand has been running at roughly 370 million gallons per day in 2026 — about 135 billion gallons a year. At today’s roughly E10-equivalent blending, EPA’s 2026-2027 Renewable Fuel Standard projects about 14.4 billion gallons of ethanol consumption. A full national switch to E15 — 15% ethanol content across the entire pool — would require closer to 20.25 billion gallons a year, an increase of roughly 5.85 billion gallons over current use.

US ethanol production capacity, per the Renewable Fuels Association’s 2026 Industry Outlook, stands at 18.5 billion gallons a year across nearly 200 biorefineries. Actual 2025 production was a record 16.49 billion gallons — meaning the industry is already running about 2 billion gallons below its own nameplate ceiling. Even filling that entire gap wouldn’t be enough: 18.5 billion gallons of total capacity is itself about 1.75 billion gallons (roughly 9.5%) short of the 20.25 billion gallons a complete, immediate, nationwide E15 conversion would need. Some further complication: a meaningful share of US ethanol production is exported rather than blended domestically, so even reaching the 18.5-billion-gallon ceiling wouldn’t necessarily mean all of it becomes available for the US pool.

None of that makes E15 a bad idea — it makes it a real but bounded one. Every gallon of the roughly 2 billion gallons of spare capacity that gets blended in as E15 displaces a gallon of petroleum-based blendstock, which is exactly the kind of margin that eases the bind refiners are in at 97.8% utilization. It just isn’t a complete substitute for new refining or ethanol capacity, and the “just switch to E15” framing tends to skip past the fact that the ethanol industry itself would need to expand roughly 10% beyond its current record output to fully supply a nationwide switch.

This is also not a hypothetical lever — it’s already partially in motion. EPA issued a temporary nationwide E15 emergency waiver on March 25, 2026, explicitly citing fuel costs from the Iran war, running in 20-day increments through the summer driving season. A permanent, year-round E15 bill (H.R. 1346) passed the House in May 2026 on a bipartisan 218-203 vote and is currently before the Senate, folded into a broader Agriculture Act provision. The emergency waiver is a stopgap; a fully wired-in nationwide E15 market would take longer to build out — both in infrastructure (RVP-compliant storage and dispensing) and in ethanol supply — than a summer waiver, but it moves in the direction the refining math actually supports, unlike an export ban.

What to watch

  • Whether the Senate acts on H.R. 1346 or the Agriculture Act’s E15 provision, and on what timeline
  • Whether US ethanol producers announce new capacity additions in response to sustained E15 demand signals, closing some of the 1.75-billion-gallon gap
  • Refinery utilization and yield data in the coming months — a further rise in distillate yield would show refiners actively leaning into the diesel/gasoline trade-off
  • Whether the diesel export ban idea resurfaces if prices don’t come down on their own, and whether any revived version carves out Mexico given how exposed that relationship is

This is a fast-moving story — the export ban proposal, the price levels, and the E15 legislative timeline could all change. This article may be updated as more information develops.

This analysis is for informational purposes only and does not constitute investment advice. See our disclaimer for details.