“Just keep the diesel here” has become the most popular energy policy idea in Washington this fall. Diesel is at record prices, and the U.S. is exporting record volumes of it (1.88 million barrels a day in one week this summer), so the logic goes: stop the exports and the price comes down. On September 23, Politico reported the White House was preparing a 90-day ban on diesel exports; a White House official denied it the same day, and the administration has since signaled it is not pursuing a flat ban. We suspect the idea is more zombie than corpse, so it’s worth thinking through what a ban would actually do.
Our short answer: a diesel export ban would make diesel cheaper and everything else more expensive. It would force U.S. refiners to cut crude runs by roughly 4 million barrels per day (mbd) – something like 20-25% of what they process today – because refineries need to export diesel to stay in balance. Those run cuts take roughly 2 mbd of gasoline and nearly 500 thousand barrels per day (kbd) of jet fuel off the market along with the diesel. Gasoline and jet then must be imported from a world refining system that is already short. Prices for those fuels will rise to import parity – and import parity itself will rise, because the world has no spare product to send us. The diesel price will crash in the U.S. and spike in the rest of the world. Traders will stockpile diesel and diesel feedstocks as the futures market immediately flips to contango.
Gasoline retail prices immediately jump while retail diesel follows slowly (the classic “rockets and feathers” pattern), and most Americans – who buy gasoline every week and never buy diesel – wind up paying more, not less. Soybean oil prices are challenged too, as the BOHO[1] spread widens and biomass-based diesel blending must overcome the very low diesel price through lower bean oil prices and / or higher RINs
This article walks through the logic and the first-order numbers. The second-order work – product-by-product price impacts, refinery-level exposure, region by region, the forward curve, and what a partial ban or carve-outs would do – is the kind of analysis we build for clients.
Why Is a Ban Even on the Table?
We laid out the mechanics of recent record diesel prices and why the crack has decoupled from crude in a recent article titled “Low Tanks, High Margins.” One of the authors of that article (and this one) drives a diesel sport wagon and can attest that prices have climbed even further since it was written. National average retail diesel set a record $5.85/gal on September 4, broke $6 a week later, and reached roughly $6.50 by late September – up about two-thirds from a year ago. Iowa diesel has been quoted at $6.57. California diesel is the highest in the country at over $8.00 per gallon.
As we described in Low Tanks, High Margins, this isn’t a crude problem. It’s a refining capacity problem. The Iran war and the closure of the Strait of Hormuz removed roughly 1.2 mbd of diesel supply, Russia’s own diesel export ban took out another 0.8 mbd on top of the refinery capacity Ukrainian drones have knocked offline, and China has cut back product exports. Valero puts war-related refinery outages at about 5 mbd of capacity. U.S. refineries are running at about 98% utilization with no headroom left.
The politics are not hard to read. Senator Chuck Grassley (R-IA) has framed an export ban as a diesel embargo on the model of the 1970s agricultural embargoes. Representative Ashley Hinson (R-IA), in a tight Senate race, has endorsed a pause, and Majority Leader John Thune (R-SD) is “open to exploring” one. Oil-state Republicans call it a gimmick. The administration is split: the President has voiced support, while Energy Secretary Wright (who has called a ban a “blunt tool” and prefers voluntary redirection), Treasury Secretary Bessent and Interior Secretary Burgum (who has flagged retaliation risk) oppose it. The pressure is midterm-driven – Iowa, Kansas, and Nebraska seats are in play – and it is harvest season. Combines and grain trucks run on diesel.
First Problem: What Exactly Is “Diesel”?
Before anyone can put a number on a ban, somebody has to say what’s banned. Nobody has. EIA reports exports of “distillate fuel oil,” a bucket that includes ultra-low-sulfur diesel (ULSD), heating oil, marine gasoil and off-road fuel. Does a ban cover finished diesel only, or everything in the distillate boiling range? What about refinery intermediates such as light cycle oil, straight run diesel, or light gasoils, which trade across the Gulf Coast every day? Is jet fuel (a kerosene, but it sits in the distillate pool) in or out? Are renewable diesel (RD) and biodiesel (BD) “diesel”? Every one of those answers changes the volume at stake, and anything left out of the definition becomes a loophole (more on that below).
There is also no modern precedent. The last U.S. restriction on energy exports was the crude oil export ban, a legacy of the 1970s price controls, and Congress lifted it in December 2015. A diesel ban would be the first outright ban on U.S. energy exports since then, and it would land on an industry that has spent a decade building its logistics around the export dock. Our working assumption, absent any text, is that a ban would cover all distillate variations, including jet fuel. We carry that assumption through the numbers below.
How Much Diesel Actually Leaves the Country?
In 2025, the U.S. exported about 1.25 mbd of distillate. That figure is already stale. Exports averaged roughly 1.4 mbd in the first half of 2026 and about 1.7 mbd on a four-week basis heading into August, with a record 1.88 mbd the week of July 31; S&P Global counted a record 54 million barrels for the month of August. Meanwhile, the roughly 85 kbd of distillate the U.S. imports – mostly from Canada into New England and the Mid-Atlantic – has fallen, so net exports are at a record. For scale, U.S. diesel exports are about one-fifth of the roughly 8 mbd seaborne diesel trade, and Capital Economics estimates the 2026 U.S. export surge has offset about half the global supply lost to Russia and the Iran war. The rest of the world has been leaning hard on Gulf Coast refineries.[2]
Where does the diesel go? In 2025 the top destinations were Mexico (about 220 kbd, or 17%), Chile, Brazil, the Netherlands, Ecuador, the United Kingdom, Peru, Panama and Guatemala. Latin America took about 63% of the total and Europe about 22%; the Caribbean, which is supplied almost entirely out of the Gulf Coast, took another 9%. Vessel tracking for 2026 shows the same picture with a heavier tilt toward the hemisphere: South America alone is about 41%, and adding Mexico and Central America brings the regional share to roughly 68%. U.S. diesel is about one-third of Latin America’s diesel consumption. Hold that thought; it matters when we get to retaliation.[3]
For the rest of this article, we use a 2026 basis of roughly 1.5 mbd of exports – between the first-half average and the summer peak.
Refiners Can’t Store It, So They’ll Get Creative to Keep Crude Runs Up
Today, with the diesel crack far above gasoline and jet, every U.S. refiner that can run in max-diesel mode is doing so. On day one of a ban, roughly 1.5 mbd of diesel that was headed for a ship has nowhere to go. The domestic market cannot absorb it; U.S. demand doesn’t jump 35% because a cargo got cancelled. So, the barrels go to tank… for a while.
The problem is there isn’t much tank to go to. U.S. distillate stocks stood at about 105 million barrels on September 25, ~14% below the five-year average and the lowest for that week in 45 years. East Coast stocks are at a record low of roughly 20 million barrels. Refilling the entire system back to the five-year average (about 123 million barrels) absorbs only ~11 days of a 1.5 mbd surplus. Ninety days of trapped exports is roughly 135 million barrels – more than the total distillate inventory in the country today. There is simply not enough tankage to carry a ban of any meaningful length, so production must come down.[4]
U.S. Distillate Fuel Oil Stocks: 2026 vs. Prior Five-Year Range
Source: Stillwater analysis of U.S. Energy Information Administration, Weekly Petroleum Status Report (Weekly U.S. Ending Stocks of Distillate Fuel Oil, series WDISTUS1), data through week ending September 25, 2026; released September 30, 2026. Shaded band and dashed line show the 2021–2025 range and average for the same week of the year.
The first move is to come out of max-diesel mode: pull light diesel into jet, drop heavy diesel into gasoil, and switch the crackers and every other unit that can into max-gasoline mode. In our experience that flexibility is worth perhaps 20% of diesel output, call it 250 kbd. With a strict export ban, the remaining 1.25 mbd goes away only one way: by running less crude. Distillate is roughly 30% of the barrel on average, so backing out that much diesel means a crude run cut on the order of 4.2 mbd – roughly a quarter of the 17.5 mbd U.S. refineries are processing today. You can’t cut runs and lose only the diesel, so the cut also removes about 2 mbd of gasoline (46% yield) and 0.5 mbd of jet fuel (11% yield). Ban exports of one product, lose all three.[5]
Anyone who trades these barrels will see a secondary effect right away. ULSD is steeply backwardated today; prompt barrels are worth far more than deferred ones, which is the market telling you to sell your inventory now. A ban turns that upside down. Prompt Gulf Coast diesel must clear against local demand plus whatever tank space exists, while deferred months reflect a world after the ban lifts. The curve flips into contango on day one, and refiners and traders get paid to store diesel rather than sell it. This could blunt the pump-price relief the ban was supposed to deliver and could create incentives for refiners to store diesel barrels in alternate locations, like converted crude tanks. Refiners will get creative to keep crude runs up and manage diesel storage – the Stillwater team came up with nearly a dozen ways they might do it. They could even cut renewables blending or push for an RVO waiver, perversely hurting the farmers the export ban is meant to help.
The Gasoline and Jet Problem
The U.S. exported about 870 kbd of gasoline in 2025. A production cut of 1.9-2.2 mbd does not just end those exports; it leaves the U.S. needing 0.6-1.3 mbd of gasoline imports. Jet fuel flips from net exporter to net importer as well. The natural supplier is Europe, which would at that moment be scrambling to replace the U.S. diesel it had been importing. The jet crack was already around $89/bbl in mid-September, which tells you there isn’t much slack in the global jet market either.[6]
Today Gulf Coast gasoline and jet are priced at export parity, the netback from selling into Latin America or Europe. Under a ban they move to import parity, the Rotterdam or Singapore price plus freight to the Gulf or U.S. West Coast. The difference between the two is the price impact, and it goes the opposite direction from diesel. What complicates the math is that import parity itself rises from today’s levels, since there is no slack capacity in the world system. We’ve run that math by product and by region, and it is a big number.
California: The Same Math Through a Biomass-Based Diesel Constraint
California refiners export roughly 60 kbd of diesel, but the volume is concentrated at two or three plants. Those plants take the hit: they come out of max-diesel and cut runs. Apply the same 30% distillate yield and the state loses on the order of 200 kbd of crude processing – a large slice of what remains of California’s refining base after the recent closures – along with roughly 90 kbd of gasoline and 20-30 kbd of jet. California already imports both. Under the ban it would have to import more, through marine terminals and pipelines that are already congested. The result is a state where diesel retail (about $8.18/gal on September 28th, against $6.38[7] nationally) comes down somewhat while gasoline and jet move up.[8]
Renewable diesel adds a wrinkle unique to California. Cheap trapped petroleum diesel hurts RD blending economics as the BOHO spread widens. Refiners and blenders may try to back RD out to keep crude runs up – every barrel of RD not blended makes room for roughly three barrels of crude processing. The dynamics get complicated because LCFS and RFS credit prices, not just the BOHO spread, drive blending, and because whether RD and BD even count as “diesel” under a ban goes back to the definition problem above. We work through this supply and demand analysis regularly with our West Coast Fuels Outlook subscribers.
What Happens at the Pump
In the first few weeks, refiners fight for market share. Rack diesel on the Gulf Coast falls quickly as the surplus hits and keeps falling until run cuts bring supply back into balance with domestic demand. Two things limit how far it falls: the contango incentive to store rather than sell, and the old rockets-and-feathers lag between wholesale and retail, which we have written about before. Retail diesel comes down, but slowly, and by less than the headlines would suggest. Meanwhile gasoline and jet are rising toward import parity. For the farm and trucking constituencies pushing the policy, the relief is real but temporary. It ends the day the ban does, or sooner if the market front-runs the expiration.
Who Gets Hurt Abroad – and How They Push Back
Mexico, Brazil, and the United Kingdom are the most exposed buyers. The Caribbean, which has essentially no alternative supplier, would be hit hardest on a per-barrel basis. Now the thought we asked you to hold: Mexico, Brazil, Colombia, and Ecuador are not just diesel customers. They sell crude to U.S. refiners. Secretary Burgum has publicly flagged the retaliation risk, and the obvious compromises (a partial ban, or exemptions for neighbors and the Caribbean) change the whole analysis. A ban with carve-outs is a different policy with different numbers.
The Loopholes
Every export control creates an arbitrage, and this one would create several. If the Caribbean or the Bahamas are exempt, expect cargoes to those islands to surge and then sail right back out of the storage terminals there. A distillate barrel that can’t leave as diesel may well leave as gasoil, kerosene, jet or blendstock, depending on how the rule is written. And the calendar works against the policy: the announcement window triggers a pre-ban export rush, and the expiration date triggers a post-ban catch-up that drains stocks just as the ban lifts.
How to Think About the Cost
We think about it in three buckets, order of magnitude only.
- Lost refining margin: a 4.2-4.8 mbd run cut against a 3-2-1 crack of $65-70/bbl (August averaged a record $65.61) is roughly $275-335 million per day, or $25-30 billion over 90 days.
- Lost export earnings: about 1.5 mbd of diesel at roughly $220/bbl is another $330 million per day, or about $30 billion over 90 days.
- On the consumer side, which is the hardest to see from Washington: every 10 cents per gallon added to gasoline costs U.S. drivers about $38 million a day on roughly 9 mbd of demand, before jet.
Multiply these by the import-parity swing discussed above and this becomes a very expensive way to buy a few weeks of cheaper diesel.[9]
Bottom Line
A diesel export ban is really a refinery run cut. Diesel can’t be stored at this scale and can’t be made without also making gasoline and jet, so keeping 1.5 mbd of diesel at home means taking roughly 4 mbd of crude out of U.S. refineries and importing the gasoline and jet that disappear with it. Diesel gets cheaper for a while. Soybean oil prices likely drop, hurting the very farmers the export ban was meant to help. Everything else gets more expensive. The forward curve flips and pays refiners and traders to hold instead of sell diesel, and the countries that sell us crude are the ones left short of fuel.
The idea has been denied once and will probably come back in modified form: a partial ban, a time-limited pause, carve-outs for neighbors. Each version has different winners and losers, and the differences run to hundreds of millions of dollars a day. If you refine, market, trade or import these products, the question worth asking now is what your exposure looks like under each version.
A diesel export ban – full, partial, or merely threatened – hits every refiner, marketer, trader and importer differently. Stillwater Associates has built the balances behind this piece: product-by-product price impacts, refinery-level exposure, California marine import constraints, and the forward-curve dynamics. To discuss what it means for your business, contact us.