LARRY. JOHNSON on oil refining and markets

This is extremely important to understand

How Does a Refinery Built to Process Sour Crude Differ From a Refinery to Process Sweet Crude?

Larry C Johnson

Jul 29, 2026

You may think this is a stupid or irrelevant question to be asking when news is just breaking that Iran has launched some per-emptive strikes on US bases in the Persian Gulf and Jordan, but trust me, it is a very relevant question. (Note: I will deal with the military fallout from today’s new attacks in my post on Wednesday.)

The short answer to the question I posed above is that a sour-crude refinery is built around one dominant problem that a sweet-crude refinery is largely spared — sulfur — and almost every hardware difference cascades from that. But there are actually two variables doing the work here, and they’re usually conflated: sulfur content (sweet vs. sour) and density (light vs. heavy). They correlate in the real world — most sour crudes are also heavy (Arabian Heavy, Urals, Canadian dilbit, Venezuelan), most sweet crudes are lighter (WTI, Brent, Bonny Light, US shale) — so a “sour refinery” in practice is usually also a “heavy refinery,” and it’s worth keeping the two axes distinct because they drive different equipment.

Son of the New American Revolution is a reader-supported publication. To receive new posts and support my work, consider becoming a free or paid subscriber.

Sour means high sulfur (roughly >0.5%, and Gulf grades run 1.5–4%+). Sulfur is a problem in two ways: it’s a contaminant you have to strip out to make spec-compliant fuel that you can sell, and it corrodes the plant itself. So a sour refinery is defined by four hydroprocessing and sulfur-handling systems that are not present in the same scale in a sweet refinery. I am talking about the following:

Hydrotreaters, and lots of hydrotreating capacity — units that combine the feed with hydrogen over a catalyst to convert sulfur into hydrogen sulfide (H₂S) so it can be pulled out. Every major cut (naphtha, kerosene, diesel, gasoil) needs its own treating.

A hydrogen source at scale. All that hydrotreating (and hydrocracking) consumes enormous volumes of hydrogen, so a sour/heavy refinery typically runs a dedicated steam methane reformer to manufacture hydrogen. A simple sweet refinery can often subsist on the hydrogen thrown off as a byproduct of its catalytic reformer.

Amine units + a Sulfur Recovery Unit (Claus process) + tail-gas treating. This is the back end that takes the H₂S you’ve stripped and converts it to elemental sulfur for sale. A sweet refinery may have a token SRU; a sour refinery’s sulfur block is a major, capital-intensive part of the plant. A big Gulf refinery can produce thousands of tons of sulfur a day as a side product.

Metallurgy. Because H₂S and organic acids attack carbon steel — via sulfidation and, where hydrogen is present, hydrogen-induced cracking and high-temperature hydrogen attack — sour plants are built with upgraded metallurgy: stainless and chrome-moly alloy cladding in the crude unit overhead, hydrotreater circuits, and hot sections. That alloy content is a big reason sour refineries cost more to build even before you count the extra units.

Are you with me so far? Let me explain why this asymmetry between sour crude refineries and sweet crude refineries matters strategically — The two plant types are not interchangeable, and the switching costs run mostly one direction.

A refinery configured and optimized for a specific sour/heavy diet (say, Urals, or Arabian Heavy, or Venezuelan/Canadian heavy) can’t freely swap to another crude without yield and economic penalties — its coker, hydrogen balance, and hydrotreater sizing were tuned to that feed. This is exactly why sanctioned-crude reroutings are sticky: Indian and Chinese refiners that took discounted Urals, or the Gulf/Chinese teapots’ appetite for heavy sour, reflect plants built for that assay, not spot opportunism.

A complex sour refinery can process sweet crude (it’s over-built for it, so it just runs its expensive units under-utilized — inefficient but feasible). A simple sweet refinery generally cannot process sour crude — it lacks the hydrotreating, hydrogen, sulfur recovery, and metallurgy to handle it at all. That one-way flexibility is why global sour/heavy conversion capacity is the real constraint, and why losing a specific complex refinery (or a specific heavy-crude supply it was built around) can’t be quickly back filled elsewhere.

So when you see the US or Iran strike a specific refinery, or a crude grade knocked off the market, the question that determines the real supply impact isn’t barrels-for-barrels — it’s which configuration was hit and whether the displaced crude has anywhere else to go that was actually built to digest it. A million barrels of Arabian Heavy stranded by a Hormuz disruption can’t be absorbed by simple sweet refineries sitting idle in some other region; it needs deep-conversion capacity specifically, and that capacity is concentrated, expensive, and slow to build.

The core asymmetry is that the crude coming out of the Gulf is overwhelmingly heavy and sour, and only four geographically concentrated set of refineries were ever built to digest it. These are:

Reliance’s Jamnagar (Gujarat, ~1.4 mbpd across two refineries) is the single most important node — it’s among the highest-complexity refineries on earth, purpose-built to run cheap heavy sour from anywhere and crack the resid into clean products.

China’s mega-refineries and Shandong teapots are the second great sink. The state-of-the-art complexes (Rongsheng/ZPC at Zhoushan, Hengli at Dalian) plus the independent teapot cluster in Shandong are configured for heavy sour and are the designated home for sanctioned barrels — Iranian Heavy, Venezuelan Merey, discounted Russian ESPO/Urals. This is the destination that makes Iran’s crude exports viable at all, and it’s Hormuz-and-Malacca exposed.

Northeast Asia — South Korea (SK, GS Caltex, S-Oil) and to a lesser extent Japan — runs high-complexity plants on a steady Gulf sour diet (historically heavy Saudi, Kuwaiti, and pre-sanctions Iranian). These are among the most Hormuz-dependent refiners in the world, with almost no domestic crude and limited ability to swap feed quickly.

The US Gulf Coast is the outlier that matters for the strategic picture — it’s enormous deep-conversion heavy-sour capacity (Valero, Motiva’s Port Arthur, ExxonMobil Beaumont, the coking belt), but it is not primarily Gulf-fed. It was rebuilt in the 2000s around Venezuelan and Mexican Maya, and now leans heavily on Canadian heavy via pipeline. So the USGC is heavy-sour hungry but largely insulated from a Hormuz event — which is exactly why it can’t easily backfill stranded Gulf barrels for Asia: it’s already running its coke drums full on Western Hemisphere heavy.

So the vulnerability isn’t measured in barrels off the water — it’s measured in coking and hydrocracking capacity that has lost its designed feed, and that capacity is concentrated in four places (Jamnagar, coastal China, Korea, and a USGC that’s already full on Canadian). That concentration is the thing worth watching: a sustained double-chokepoint event doesn’t ripple evenly across the refining world, it lands almost entirely on those Asian deep-conversion hubs and on the diesel market they anchor.

What I have outlined and discussed above just scratches the surface of the enormous economic stakes that are at risk if the Strait of Hormuz remains closed for an extended period of time. Besides the shortage of the sour crude and shortage of sulphur, there are also major deficits in urea, LNG and helium. It is conceivable that the economic damage from the US war on Iran will exceed any physical damage inflicted by missiles and bombs.

Refinery Configuration Matters—But Markets Matter More

Larry C Johnson

Jul 30, 2026

Let me introduce you to my friend, Karl Miller. Karl Miller is a US energy-sector figure known primarily as a trader, investor, and distressed-asset specialist rather than a sell-side or think-tank “analyst” in the narrow sense. Per his own professional materials and a Risk.net profile: his career began on Wall Street in 1989 at Dean Witter Reynolds, then moved into futures and options trading at Copia in New York; he later worked in the energy arm of Électricité de France (EDF) and became a partner at NEAH Energy (sometimes styled NEAH Power/Global Energy).

Karl has played a key role in educating me about the complexity of the oil industry and he had some comments on my last article. So here is his take:

Son of the New American Revolution is a reader-supported publication. To receive new posts and support my work, consider becoming a free or paid subscriber.

Larry,

I enjoyed reading your article on sour crude refining because it highlights an issue that is often overlooked in discussions of energy security: not all crude oil is interchangeable, and not all refineries are capable of processing every crude grade. Too many commentators reduce oil markets to barrels per day, ignoring sulfur content, density, refinery complexity, and conversion capacity. Your explanation of why heavy sour crude requires extensive hydrotreating, hydrogen production, sulfur recovery, upgraded metallurgy, and deep-conversion equipment is technically sound and provides useful context for understanding why refinery configuration is as important as crude supply.

Your central thesis—that refinery configuration constrains the world’s ability to absorb the loss of Gulf heavy sour crude—is fundamentally correct.

Where I believe the analysis becomes less convincing is in its strategic conclusions, particularly regarding the degree to which the U.S. Gulf Coast would be insulated from a prolonged disruption of Middle Eastern heavy sour crude supplies.

The distinction is an important one.

Your article largely equates physical supply resilience with economic immunity. Those are not the same.

The U.S. Gulf Coast is unquestionably less dependent on Persian Gulf crude than Northeast Asia. Much of its heavy sour feedstock comes from Canada, Mexico, Colombia, Brazil, and other Western Hemisphere producers. That diversified feedstock base gives American refiners greater operational resilience than refiners whose crude supply depends almost entirely on the Strait of Hormuz.

But resilience should not be mistaken for insulation.

Heavy sour crude is traded within a global commodity market. Canadian Western Canadian Select, Mexican Maya, Colombian Castilla, Brazilian heavy grades, Iraqi Basrah Heavy, Saudi Arab Heavy, Kuwaiti Export Crude, and Venezuelan blends ultimately compete in the same international pricing system. Remove several million barrels per day of Middle Eastern heavy sour crude from global trade and every remaining substitute becomes more valuable.

The Gulf Coast would therefore not stand outside the disruption. It would participate in it through higher acquisition costs, tighter supplies, and intensified international competition for replacement barrels.

The assumption that Canadian heavy crude would continue flowing to the United States largely unchanged is also open to question.

Canada is no longer a captive supplier to American refiners. The expansion of export infrastructure on Canada’s Pacific Coast has created increasing opportunities to reach Asian buyers directly. If refiners in China, South Korea, Japan, or India suddenly faced simultaneous disruptions in both the Strait of Hormuz and the Red Sea, they could offer premiums large enough to offset the additional transportation costs of shipping Canadian crude across the Pacific.

Commodity producers maximize netback value, not geographic proximity.

If Asia becomes the highest-paying destination, commercial incentives will redirect as many exportable barrels as infrastructure allows.

Nor would massive diversion be required to affect U.S. refiners.

Oil prices are established by the marginal barrel. Even relatively modest shifts in Canadian exports toward Asian markets would tighten supplies available to Gulf Coast refiners and increase the acquisition cost of every remaining heavy crude barrel. Existing pipeline networks certainly provide American refiners with logistical advantages, but pipelines do not suspend the laws of global price formation.

The same principle applies to every alternative heavy sour producer.

Mexican production remains constrained. Colombian exports are finite. Brazilian heavy grades are increasingly sought after. Venezuelan production remains subject to political and infrastructure limitations. None of these sources possesses sufficient spare capacity to replace Gulf exports on short notice.

The result wouldl be bidding competition rather than seamless substitution.

I also think the article understates the broader consequences of a simultaneous disruption of both the Strait of Hormuz and the Red Sea.

Such an event would not merely interrupt crude flows.

It would reshape the economics of the global refining system.

Asian deep-conversion refineries would experience severe feedstock shortages. Demand for diesel, jet fuel, gasoline, and other refined products from alternative suppliers would increase dramatically. American Gulf Coast refiners would likely continue operating because they retain access to Western Hemisphere crude. However, they would simultaneously confront higher feedstock costs and stronger international demand for their refined products.

Refining margins might improve.

Domestic fuel prices would almost certainly rise.

American consumers would therefore experience the effects of the disruption even if American refineries never lost physical access to crude.

That distinction is critical.

The relevant question is not simply whether Gulf Coast refineries can continue operating.

The relevant question is under what economic conditions they continue operating.

A refinery that remains supplied while paying dramatically higher prices for feedstock and exporting into an undersupplied global market is not insulated from the disruption. It is operating within it.

There is another consideration worth emphasizing.

Refinery configuration determines what can be processed efficiently.

It does not determine how markets respond.

Engineering constraints are only one component of a much larger system that includes shipping capacity, insurance markets, futures trading, strategic petroleum reserves, inventory management, diplomatic responses, substitution between crude grades, refinery optimization, and changes in consumer demand. Modern oil markets have repeatedly demonstrated remarkable adaptability in response to sanctions, wars, hurricanes, and production outages. The adjustments are rarely painless, but they are seldom as rigid as engineering diagrams alone might suggest.

Your article succeeds in explaining why heavy sour refining capacity is strategically valuable.

Where it overreaches is in implying that the United States occupies a position largely outside the consequences of losing Gulf heavy crude.

The Gulf Coast’s strategic advantage is one of relative resilience, not immunity. It is less vulnerable than Northeast Asia to an immediate physical interruption of heavy sour crude because of its diversified North American feedstock base. Yet it remains fully exposed to the economic consequences of losing the world’s largest concentration of exportable heavy sour crude. Higher feedstock costs, intensified competition for Canadian and other non-Middle Eastern grades, shifting trade flows, tighter refined-product markets, and higher domestic fuel prices would all transmit the effects of a Middle Eastern embargo or a prolonged closure of the Strait of Hormuz directly into the U.S. refining sector.

Ultimately, I think your strongest point—that refinery configuration constrains the world’s ability to absorb the loss of Gulf heavy sour crude—is well supported. The weaker point is the implication that the United States somehow stands outside those constraints. In reality, the U.S. Gulf Coast is better positioned than most regions to weather such a shock because it possesses world-class deep-conversion refining capacity and access to diversified heavy crude supplies. Those advantages make it more resilient than many of its competitors, but they do not exempt it from the economic realities of an integrated global commodity market.

In a major disruption, the challenge facing Gulf Coast refiners would not be an inability to process heavy sour crude. It would be the escalating cost of acquiring the heavy sour crude upon which that refining system depends.

The engineering is correct.

The economics are considerably more complicated.