Why banning diesel exports would not help consumers

A diesel export ban is the kind of policy that polls well and trades poorly. With the AAA national average at about $6.53 a gallon as of September 22, 2026 — a record — and California well above $8, the political impulse is obvious: keep more barrels at home.

That impulse misunderstands how U.S. refining actually works. The United States already makes far more distillate than it burns. The problem is not a national shortage of molecules. It is where those molecules sit, how they move, how thin the buffer is once you leave the Gulf Coast, and what refiners do when the export valve that funds high utilization is closed.

The country is long diesel. The map is not.

U.S. refiners have been running near the physical limit. Utilization has spent much of late summer in the mid-to-high 90s, touching about 98 percent in late August — the highest stretch in years. Operable atmospheric distillation capacity as of January 1, 2026, was about 18.2 million barrels per calendar day, down more than 250,000 b/d from a year earlier after the LyondellBasell Houston and Phillips 66 Los Angeles closures. Distillate production has been running around 5.1–5.3 million barrels per day. Domestic distillate product supplied has been closer to 3.4–3.8 million barrels per day. Exports have absorbed the surplus, often 1.3–1.9 million barrels per day.

That is the core arithmetic. American Fuel & Petrochemical Manufacturers put it cleanly: production near 5.3 million barrels per day against domestic demand near 3.6 million. Ban the export outlet, and you do not automatically get cheaper diesel in Boston or Sacramento. You get surplus product stacked on the Gulf Coast, compressed crack spreads, and then lower runs. Gasoline and jet fuel come out of the same barrel. Cut diesel output, and you cut those too.

Catalytic hydrotreating capacity for diesel fuel as of January 1, 2026, was about 4.43 million barrels per stream day nationally. PADD 3 (Gulf Coast) holds the bulk — Texas about 1.42 million and Louisiana about 817,000. PADD 1 (East Coast) has only about 292,000. That imbalance is why “we have lots of diesel” and “New England is tight” can both be true on the same Wednesday.

Inventories look “stable.” The buffer is almost gone.

National distillate stocks were 107.9 million barrels for the week ending September 11, up 1.6 million from the prior week. Days of cover have hovered near 30. That headline is less comforting than it looks. EIA’s September Short-Term Energy Outlook, completed September 3, still projects inventories falling below 100 million barrels in September and remaining below the 2021–2025 five-year low through most of 2026 and 2027. East Coast stocks have already printed historically low readings — including a late-August PADD 1 print near 19.3 million barrels, among the lowest in the modern EIA series. New England and the Lower Atlantic have been especially thin.

Thirty days of national cover is not thirty days of cover in every PADD. Gulf Coast tanks can build while PADD 1 drains. That is exactly what several late-summer EIA weeks showed: the national build was a Gulf Coast story. The East Coast and West Coast were still living on a short leash.

When utilization is 97–98 percent, the only shock absorber left is inventory and inter-regional logistics. There is almost no idle still to call. Midwest plants have even run above nameplate. An unplanned outage — ExxonMobil Joliet’s mid-September power loss and flood is the live example — does not get replaced by “more exports coming home.” It comes out of already-thin regional tanks.

If refiners cannot chase the high-margin barrel, they will schedule the outage

High distillate cracks are why plants have deferred turnarounds. EIA and industry reporting show planned shutdowns running well below recent-year averages through the first half of 2026. That is not charity. It is economics.

An export ban would collapse the Gulf Coast netback that is currently paying those high runs. Refiners cannot store unlimited ULSD. If the export dock is closed and domestic pipes and Jones Act tonnage cannot clear the barrel at a profit, the rational response is to cut crude runs or pull forward maintenance. Deferred work does not vanish. It shows up in February and March — right before planting — when seasonal runs already fall by hundreds of thousands of barrels per day versus the annual average.

That is how a policy sold as “protecting the domestic market” would shrink the domestic market. The fragile regions are the ones that lose first, because they do not sit on top of Motiva, Galveston Bay, Beaumont, Baytown, and Garyville.

Who actually makes the diesel

The U.S. diesel system is a Gulf Coast system with satellites.

Largest operable plants by calendar-day crude capacity as of early 2026 include Motiva Port Arthur (about 656,000 b/cd), Marathon Galveston Bay (about 631,000), Marathon Garyville (about 617,000), ExxonMobil Beaumont (about 612,000), and ExxonMobil Baytown (about 564,500). ExxonMobil Baton Rouge, Citgo Lake Charles, Valero Port Arthur, and Chevron Pascagoula fill out the heavy distillate belt. Midwest anchors include BP Whiting (about 435,000) and ExxonMobil Joliet (about 267,000–275,000). West Coast capacity has been shrinking: Phillips 66 Los Angeles closed in October 2025, and California’s remaining complex — Marathon Los Angeles, Chevron El Segundo and Richmond, PBF Torrance and Martinez — is both smaller and more isolated.

PADD 3 is the surplus machine. PADD 1 and PADD 5 are the deficit machines. Policy that strands barrels in Texas and Louisiana does not automatically fill New Haven or Los Angeles.

The states most exposed

Risk is not evenly distributed.

East Coast / New England. PADD 1 has little refining, record-low seasonal distillate stocks, and winter heating-oil demand on top of trucking. Massachusetts, Connecticut, New York, New Jersey, Pennsylvania, Maryland, and Maine are first in line if Colonial Pipeline volumes slip, a Gulf storm hits, or import parity rises because Europe is even shorter. A U.S. export ban that tightens Europe raises the price of the barrels the Northeast still has to buy.

West Coast / California system. California has lost a large share of in-state capacity. Washington, Oregon, Nevada, and Arizona draw from that same isolated PADD 5 pool. There is little pipeline from the Gulf. Waterborne rescue depends on scarce Jones Act ships — or on a waiver.

Midwest harvest belt. Utilization is already above nameplate in PADD 2. Joliet and Whiting matter for Illinois, Indiana, Iowa, Michigan, Ohio, Wisconsin, and neighboring farm states. High retail prints in Indiana, Michigan, Illinois, Ohio, and Wisconsin are not a coincidence when a regional plant trips.

High-tax, high-spec islands. California’s CARB diesel and tax stack put it in a class by itself. Hawaii and Alaska are structurally import-dependent. Rural high-use states — Wyoming, North Dakota, Alaska — feel diesel as an input tax on production, not just a pump price.

Gulf Coast pump prices can look “better” even in a crisis because that is where the molecules are born. An export ban would not move those molecules north and west by decree.

The Jones Act is the hidden constraint — and the waiver data prove it

Cato Institute’s Jones Act Waiver Tracker documents what happens when the 1920 cabotage rule is lifted for energy cargoes. DHS issued a broad waiver on March 17, 2026, later extended. MARAD voyage reports feeding Cato’s dashboard have shown well over 160 completed voyages in the first 115 days alone, with 135 unique vessels and nearly 40 million barrels moved across many product categories, including diesel. Gulf-to-West Coast clean-product movements jumped by multiples versus recent full years. New England and Puerto Rico saw large percentage increases off tiny baselines. More jet fuel moved to PADD 5 under the waiver than in decades of Jones Act-constrained history combined.

That is the logistics problem in one dataset: the diesel exists on the Texas-Louisiana waterfront. Getting it to the deficit coasts on U.S.-built, U.S.-flagged, U.S.-crewed tankers is expensive and capacity-constrained. Foreign-flag ships under the waiver have been functioning as a temporary extension of the domestic distribution system.

They have also been undercounted. Bloomberg and Cato analysis in mid-September found voyages missing from MARAD’s public filings — including movements to California, Hawaii, Puerto Rico, and the East Coast — that still show up in port-call and cargo data. Those unreported or late-reported liftings are part of how Gulf Coast refineries have been supplying the rest of the country while official weekly balances look tighter than the physical reality. Ban exports and let the waiver lapse, and you close both the international valve and the cheapest domestic waterborne bypass at the same time.

Defense Production Act: expand plants and pipes, don’t embargo the surplus

If the goal is more diesel in the wrong ZIP codes, the tool that matches the diagnosis is capacity and logistics, not an export embargo.

On April 20, 2026, the White House issued Title III determinations under the Defense Production Act declaring several energy systems essential to national defense. One covers domestic petroleum production, refining, and logistics capacity, including exploration and production, gathering and transmission pipelines, storage, and marine terminals. Another covers large-scale energy and energy-related infrastructure — engineering, site work, permitting support, manufacturing, and enabling infrastructure. Those determinations can be used nationally. They authorize purchases, purchase commitments, loans, loan guarantees, and related incentives, and they waived several statutory prerequisites so DOE can move faster.

Reuters reported in September that the White House is weighing how to apply that authority to refining after a meeting with about a dozen refiners. Industry’s message was consistent with physics and capital budgets: spend on debottlenecking and expanding existing plants, not on a greenfield refinery that takes years and billions. Marathon Garyville’s long climb from roughly 539,000 to 617,000 barrels per day is the template. DPA has not historically been used to add refining capacity; the April determinations created the legal hook. Invocation can be national because the determinations already are. Implementation still has to pick projects, write contracts, and survive permitting — DPA is not a magic bullet.

Can pipelines be built with it? In statutory terms, yes: petroleum “logistics capacity” in the April determination expressly includes gathering and transmission pipelines, storage, and marine terminals. Title III money and priority ratings can support pipe, terminals, and related equipment. DPA does not repeal NEPA, state siting, or eminent-domain politics by itself. Separate legislation such as the proposed National Security Interstate Pipeline Act would try to expedite designation of oil, products, and gas lines as national-security projects. The honest answer is that DPA can finance and prioritize pipeline capacity; it cannot teleport steel across a courtroom. Combined with a Jones Act waiver, though, it attacks the actual bottleneck: moving Gulf diesel to PADD 1 and PADD 5.

An export ban does the opposite. It reduces the incentive to run hard, reduces the cash flow that funds expansions, and raises prices for allies who then bid more aggressively for the remaining seaborne barrel — including the import-parity barrel that heats the Northeast.

 

What analysts actually see for prices

EIA’s September STEO (forecast completed September 3, released September 9) raised its retail diesel outlook to an annual average of $5.07 a gallon in 2026 and $4.40 in 2027, up 22 cents and 33 cents from the August outlook. Those are calendar-year averages struck before the mid-September record run above $6.50. The same outlook sees diesel crack spreads above $2 per gallon from August through November, then easing into mid-2027 if Hormuz tanker traffic normalizes and some foreign distillate supply returns. Inventories stay structurally tight through most of 2027 in that base case.

Futures as of mid-September were still backwardated: New York Harbor ULSD near $5.00 for October, lower into 2027. Goldman Sachs has described diesel as the epicenter of the refined-product squeeze and lifted its view of U.S. diesel refining margins sharply — to as high as $63 per barrel in 2027 in one late-August note — while also warning that refiners maximizing diesel are tightening gasoline. Private agricultural-outlook work that holds current disruption assumptions in place produces 2027 retail paths well above EIA’s $4.40 average. The spread between “wars fade” and “both disruptions persist” is on the order of $1.50–$2.00 a gallon by next spring.

None of those paths is improved by shutting the export dock while refineries are already maxed and coastal tanks are empty.

The consumer case against the ban

Consumers do not buy a national inventory number. They buy a gallon in a specific state, after tax, after pipeline tariff, after barge freight, after a refiner decides whether this week’s barrel is worth running.

A ban would:

• Strand surplus on the Gulf Coast and cut runs, reducing gasoline and jet as well as diesel.
• Raise European and Latin American prices, which feeds back into U.S. coastal import parity.
• Remove the margin that is currently paying 96–98 percent utilization and deferred maintenance.
• Leave PADD 1 and PADD 5 still short of pipe and ships.

A better package is the one the physical market is already sketching: keep exports legal so plants keep running; extend or institutionalize Jones Act relief for energy cargoes so Gulf barrels can reach the coasts; and use DPA Title III the way the April determinations were written — to debottleneck existing refineries and to finance the pipelines, storage, and terminals that put diesel where Americans actually burn it.

Energy security starts at home. Energy dominance is what you can still sell when the rest of the world is short. Banning diesel exports would advertise scarcity, not strength — and consumers would pay for the advertisement.

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Appendix: Sources and links