This is a follow-up from my previous piece. My goal is to explain why the current structure of the US refinery industry has created a dangerous dependence on the import of high sulphur oil aka sour crude. The heart of the matter is the middle distillates from which diesel and jet fuel are produced. This is precisely where the cutoff of Persian Gulf oil threatens to bite the US economy in the ass. 

Part II: The Sour Crude Problem: How Long Can the Salt Caverns Keep Bridging the Gap?

by Larry C. Johnson

To understand how we got here you need to know how a refinery works. A refinery’s atmospheric distillation column separates crude into fractions by boiling point. The middle distillate cut, roughly the 155–360°C boiling range, is where both diesel and jet fuel come from. How much of that cut a barrel contains is largely a function of the crude’s gravity. Medium-gravity crudes in the 28–34° API range — the classic Persian Gulf sour grades like Arab Light, Basrah Medium, or Iranian Heavy — yield on the order of 30–35 percent of the barrel as straight-run middle distillates. Very light shale crudes skew heavily toward naphtha, LPG, and gasoline-range material, yielding meaningfully less distillate per barrel. Very heavy crudes skew toward vacuum gas oil and residual fuel that must be cracked before it becomes anything useful.

Cracking oil during refining is a key chemical conversion process that breaks down large, heavy hydrocarbon molecules from crude oil into smaller, lighter, and more valuable ones (such as those used in gasoline, diesel, jet fuel, and petrochemicals). Cracking yields lighter oils, gases (e.g., ethylene, propylene for plastics), and byproducts like coke. It is essential for meeting fuel demand, optimizing refinery output, and adapting to different crude types. Modern refineries rely heavily on it for efficiency and profitability.

There is a second, subtler advantage: the molecular character of the distillate cut in medium sour Gulf crudes — once hydrotreated to strip out the sulfur — produces diesel with good cetane numbers and jet fuel with acceptable freeze points without extensive additional processing. The sulfur itself is removed in hydrotreaters as a routine step (and recovered as elemental sulfur, feeding the fertilizer supply chain — a co-dependence that surfaced when Gulf sour supply was disrupted this spring). The sulfur is a manageable nuisance; the distillate-rich yield structure is the prize.

Diesel and jet fuel are also the least substitutable products in the barrel. Diesel moves freight, powers agriculture, and runs the machinery of the military; jet fuel has no commercial alternative at all. When Hormuz closed on February 28 and roughly a fifth of the world’s traded oil — most of it medium sour — stopped moving, the pressure showed up almost immediately in distillate markets. US distillate inventories were already about 8 percent below the five-year average as of late June 2026, with refineries running at 96.6 percent utilization to keep up. Gasoline can be made from almost anything; diesel and jet fuel, at scale and at reasonable cost.

This is the context for the 172-million-barrel SPR release announced by Energy Secretary Chris Wright on March 11, 2026, as the U.S. share of the IEA’s coordinated 400-million-barrel action. It is also why the release has been so heavily weighted toward the sour side of the reserve: the Department of Energy’s first exchange solicitation, covering 86 million barrels, consisted mostly of sour crude, because sour barrels were what the disrupted Gulf flows had actually removed from the market and what U.S. and allied refiners needed to keep distillate units full.

The numbers tell the story of how hard the reserve has been worked. The SPR began the year at 411 million barrels, roughly 60 percent of it sour under the reserve’s long-standing 60/40 sour/sweet design mix — approximately 245 million sour barrels. As of the week ending July 3, 2026, total inventory stood at 319.5 million barrels, the lowest level since April 1983, after weekly draws that peaked near 10 million barrels in mid-May. With the drawdown skewed toward sour caverns, the sour inventory is now plausibly in the range of 185–200 million barrels, though the DOE publishes the precise sweet/sour split only in its monthly inventory update and no official mid-year figure has been widely reported.

Legally, the binding floor — the 252.4-million-barrel minimum in the Energy Policy and Conservation Act — applies only to the Secretary’s limited drawdown authority, not to a Presidential emergency drawdown or to the exchange authority under which the current release is structured. The real constraint on how much longer sour crude can flow is not statutory. It is geological.

The SPR’s roughly 60 caverns were solution-mined into Gulf Coast salt domes, and the same physics that created them slowly consumes them. Oil is withdrawn by injecting raw (unsaturated) water at the bottom of a cavern; the water displaces the oil upward and out, but on its way to saturation it dissolves the surrounding salt. Every drawdown therefore enlarges the cavern. Sandia National Laboratories, the SPR’s geotechnical adviser since 1980, models each complete drawdown as growing a cavern’s volume by roughly 15 percent, and the caverns were designed on the assumption that each could be emptied approximately five times over its service life. Sandia’s Level III structural criteria require that the pillar-to-diameter ratio between adjacent caverns remain adequate after those five cycles; beyond that point, the salt webs separating caverns thin toward instability.

Critically, the five-cycle figure is a design average, not a per-cavern guarantee. Sandia’s published geomechanical work — and the lab’s own project managers, on the record — state plainly that the fleet is heterogeneous: some caverns retain a full five drawdowns, some three, and certain caverns should only be completely drawn down one time, after which they cannot be used again. Sandia now produces an annual report tracking the remaining available drawdowns for each individual cavern, precisely because the answer differs cavern by cavern. That cavern-level report, not any headline inventory number, is the authoritative measure of how much structural life remains.

The fleet’s history compounds the problem. A 2010 review found a fundamental mismatch between design and use: the caverns were engineered for a small number of large emergency drawdowns, but between 1996 and 2014 the reserve executed fourteen separate removals of under 10 million barrels each — congressional deficit-financing sales, test sales, and exchanges — and small partial drawdowns leach the salt in irregular “flare” patterns concentrated at the injection depth rather than uniformly. These repeated partial cycles have caused cavern deformation and salt falls. During the 2021 sales alone, over 45 million barrels of raw water went into 26 caverns, and Sandia’s monitoring flagged leaching-induced features of concern in 11 of them. On top of the 2022 Biden-era release of 180 million barrels, the 2017–2023 congressional sales, and now roughly 91 million barrels drawn since March 2026, substantial portions of the fleet — the sour caverns especially — have consumed one to two of their nominal cycles in the past four years, unevenly distributed. The reserve’s own history offers the cautionary tale: Weeks Island, an original SPR site built in a conventional salt mine, was decommissioned in 1999 after a sinkhole allowed fresh water intrusion that began eroding the facility.

Any honest answer has to separate three different clocks.

The first clock is the announced program. Roughly 80 million barrels remain of the 172-million-barrel release. At the recent pace of 5.5–6.2 million barrels per week, the program completes in about three months — into early autumn 2026. The DOE clearly believes the caverns can sustain this, since Sandia’s per-cavern drawdown accounting is an input to exactly these decisions, and the release was deliberately spread across sites and caverns to distribute the leaching.

The second clock is the sour inventory itself. At perhaps 185–200 million sour barrels drawn at 3.5–4.5 million sour barrels per week, the sour side of the reserve holds roughly 10 to 13 months of supply at crisis rates before it approaches physical exhaustion. But this arithmetic is largely theoretical, because the third clock runs out first.

The third clock is structural. Completing the current program plus meaningful additional sour draws — say, taking sour inventory from ~190 million down below ~100 million barrels — would push many sour caverns through or near a complete drawdown cycle when stacked on top of the 2017–2023 sales and the 2022 release. For the caverns Sandia has flagged as one-drawdown-only, that would be their last cycle: usable now, at the price of permanently retiring them from the reserve. For the broader fleet, it would consume a large fraction of remaining cycles and leave the DOE facing an unattractive choice on any future refill — reinject oil into enlarged, geometrically irregular caverns with thinned pillars, or solution-mine new capacity, a multi-year, multi-billion-dollar undertaking. Cavern creep closure, running on the order of 2 million barrels of capacity per year, quietly shrinks the fleet even while it sits idle.

A reasonable synthesis: the United States can probably continue drawing sour crude at the current pace through the end of 2026 — another five to six months — without crossing structural red lines, provided the draws remain distributed according to Sandia’s cavern-by-cavern accounting. Extending crisis-rate sour withdrawals much beyond that, into the 100–150-million-barrel sour inventory range, would begin permanently consuming cavern life rather than merely spending inventory, converting a recoverable drawdown into partial, irreversible decommissioning of the reserve’s sour storage. The exchange structure of the current release — with 18–22 percent premium barrels due back between November 2026 and September 2028 — implicitly assumes the caverns survive to receive them, and that Gulf sour production recovers enough to supply them. Both assumptions are plausible. Neither is guaranteed.

The deeper lesson is that the SPR was built as a bridge over short interruptions of a crude slate America no longer produces. The bridge has held through the worst supply disruption in the oil market’s history, but it is being crossed for the second time in four years, and salt, unlike policy, does not regenerate.

This brings us back to the current situation in the Persian Gulf. Iran remains in control of the Strait of Hormuz and can prevent any ship that intends to transport oil, LNG, sulphur, urea or helium to the United States or Israel from leaving the Persian Gulf. I believe that this gives Iran substantial leverage in negotiations with the US, assuming that such negotiations take place. In light of Trump’s latest threats and actions, including the imposition of new sanctions on Iran, I think the prospects for talks are dim unless Trump agrees to make major concessions that Iran will likely insist on in order to keep the negotiations alive.

The next 24 hours will tell us where we are headed… At present it looks like the US will renew its attacks on Iran’s military and civilian infrastructure. If that happens, Iran will escalate its response, which will force Trump to choose between expanding the war and damaging the US economy, or standing down and reviving the MoU. We will see.

Sources: EIA Weekly Petroleum Status Report (week ending July 3, 2026); DOE SPR Quick Facts and FAQs; DOE Statutory Authority for an SPR Drawdown (EPCA §161); Sandia National Laboratories SAND2006-3002, SAND2019-3673, CY21 Cavern Leaching Monitoring, and Annual Reports of Available Drawdowns; QCIntel (March 15, 2026); AAPG Explorer (March 2026); Sandia LabNews interview with SPR project manager Anna Lord.

https://sonar21.com/part-ii-the-sour-crude-problem-how-long-can-the-salt-caverns-keep-bridging-the-gap/

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