Long 10% in CNQ in the HFI Portfolio.

CNQ is trading at 6.8x EV/FFO at $85/bbl WTI. We don’t think that’s right at all. This is the best Canadian oil producer by a mile with decades of inventory.

Long $500,000 of CNQ at $44.98 or 11,115 shares.

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Since the Iran conflict began, many barrel counters have been able to pinpoint precisely “when” onshore oil inventories would start falling. No, it’s not because we have crystal balls. It was simply because we gave a damn.

As I explained in an article published on March 4, 2026 titled, “Why Aren’t Oil Prices At $100?“ We wrote about all the “cushions” that had to be absorbed before onshore inventories started to plummet.

Well, we are here. (Note: Please also read, “The Oil Market Breaking Point Is Here.”

B.A.C.D is coming. Big ass crude draws, and they will break the record books.

And before I continue, I want to give you an analogy. This analogy is important because it highlights what I think is going on.

Natural gas community vs the generalist

There’s another niche group that we belong to: the natural gas community.

In this particular group, we follow weather patterns, heating degree days, cooling degree days, wind, pipeline flow, and all sorts of weird data. Generalists understand better not to traverse the world of natural gas. It is the sector where generalists come to die.

Every winter, specialists in the natural gas world are keenly watching changes in weather models, particularly the one model that rules them all, ECMWF-EPS. This is the European Ensemble model, or, as it’s aptly nicknamed, King Euro.

The weather model updates four times a day, but there are two main updates, the 00z and 12z. I won’t go into the technicalities of the model, but just know that every time this is updated, natural gas prices surge or drop based on changes in heating demand.

The natural gas market has adapted to the fast-changing pace of real-time information. There are billions of dollars moving within seconds as the data changes, so the price is somewhat efficient.

But every once in a while, there’s a weather event so shocking that the model fails to price this all in at once. This was most notable at the end of January this year when a record-breaking cold blast came.

For natural gas, the proverbial “cold blast” is the one thing that would send prices to the moon.

So, if we put the current Strait of Hormuz oil outage in natural gas terms, it’s like the coldest weather event in history, lasting 66 days. And since natural gas demand is measured in real-time, the whole world can see it and price it immediately. Spot cash prices surge, demand is needed immediately, and the financial market reacts.

But the oil market hasn’t done that yet. Why?

Well, here’s your answer.

BACD: Big ass crude draws

On April 11, we published a report titled, “Making Sense Of The Oil Market.” It was hard to understand why oil prices aren’t reflecting the incoming draws we are seeing. Most energy specialists with experience in natural gas know that if projections show a large deficit coming, markets should price it in, right?

Well, the market was inefficient. BACD is here now.

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What we are witnessing with the Strait of Hormuz today is a once-in-a-lifetime type of event. I’ve always pondered how a nobody like myself got involved in energy and lived through 2 “once-in-a-lifetime” events in the span of 6 years: COVID and the Strait of Hormuz closure.

It’s a bit surreal to have built expertise in an area of the market that no one really cared about until... 4 weeks ago. The funny thing is that all the work we’ve put into grinding it over the last 10 years in this sector is starting to pay dividends now. Like the quote from Jacob A. Riis:

When nothing seems to help, I go and look at a stonecutter hammering away at his rock, perhaps a hundred times without as much as a crack showing in it. Yet at the hundred and first blow it will split in two, and I know it was not that last blow that did it, but all that had gone before.

With that, let’s dive straight into this week’s WCTW.

The Unacceptable Status Quo

I’ve read a lot of commentaries from very smart people about what the eventual resolution might look like. One of the more interesting “scenarios” I’ve seen goes something like this:

The Trump administration says that the mission is done and leaves the region, while the Iranian continues to control the Strait of Hormuz flow. Some type of toll arrangement will be in place.

I am here to tell you that it’s a non-starter.

To most outside observers, the logic is straightforward. A VLCC (very large crude carrier) carrying ~2 million bbls of crude oil, worth north of $200 million, should easily afford a toll fee of $2 million. The generalists argue that it’s just $1/bbl, a fraction of the cost of oil. But the misunderstanding is not in the economics of the toll fee, but in the ability to impose restrictions on the potential flow.

To better understand why the status quo is unacceptable, generalists should take the time to research OPEC’s history more extensively. In particular, with the help of Claude or ChatGPT, I implore you to understand why it is so hard for OPEC or OPEC+ to come to a production cut agreement.

From the outside view, OPEC, spearheaded by the Saudis, has every incentive to keep oil prices in a tight trading range. It has already formed a “cartel”, and so in theory, enforcing the production policies should be very straightforward. The logic is that if every producer in the cartel cuts production by 5%, everyone’s revenue goes up by 25%. Win, win, right?

Wrong, and that’s the issue with generalists in energy. Most people use the logical approach when the reality has nothing to do with logic.

The best example of this irrational behavior unfolded in March 2020 when the Saudis asked Russia for an additional 300k b/d cut.

Prior to March 2020, Russia was already responsible for ~300k b/d, so the additional 300k b/d would put the total production cut at 600k b/d. Russia refused to cut the additional ~300k b/d, despite it only being less than ~3% of its total production volume. What did the Saudis do? They unleashed hell.

Saudis took the view that if you aren’t willing to cut production, then everyone can feel the wrath. So instead of coming to the logical conclusion that the demand destruction from mandated lockdowns would inevitably reduce everyone’s oil production, Saudis forced the widespread sector shut-in that was to be infamous with the COVID fallout. A month and a half later? WTI went negative.

The moral of the story is that logic doesn’t drive policies, especially not in the oil market. Consider that if Iran implemented a toll fee, no matter how low it is, it would have an effective say in the flow of Gulf state traffic going forward. This is more powerful and effective than Saudi’s dominant role as the swing producer.

This is why, in my strong opinion, the Saudis would rather keep oil production shut-in by ~3 million b/d than to transport through the Strait of Hormuz. The ramifications are profound.

It Will Never Be The Same

Over the past few weeks, I’ve explained that the longer the conflict lasts, the lower the likelihood of a smooth resolution due to anchoring biases. Despite the Trump administration’s insistence that the war will be over soon, the worst-case scenario has already played out.

Oil analysts, such as myself, continue to focus on the fundamental dynamics of this fallout (i.e., how many barrels are lost, how much storage goes down, etc). But the longer-term implications are that the oil market will never be the same again.

One thing that troubles me is that the Strait of Hormuz closure was always thought of as a theoretical exercise. Imagine a child with the imagination to daydream that one day he/she might be able to time-travel or fly. It borders on fantasy land because no one has really thought about the ramifications of the closure (Strait of Hormuz) for geopolitical dynamics or trade flows.

Now that the bogeyman is out, it can never be the same again. He who controls the Strait of Hormuz controls the flow of energy worldwide. The US, as Dr. Anas Alhajji has pointed out, benefits most because it is largely self-sufficient. We can supply our domestic refineries with heavy crude from Venezuela and Canada. We are the largest producer and exporter of helium. We have access to cheap natural gas.

But for the rest of the world, the dynamic differs, and for the other Gulf Countries, the conflict that’s taking place today is existential.

As I explained in the section above, even if President Trump adopts a policy of leaving the conflict altogether and leaving Iran in control of the Strait of Hormuz, the aftereffects would be unmanageable.

Saudis, despite not having the military capabilities to combat Iran, could force the US to intervene again by structurally reducing output by ~3 million b/d.

In past “tight” oil markets, a 1 million b/d deficit can send oil prices into the stratosphere. A 3 million b/d deficit would invite armageddon. Remember that in March 2022, IEA issued an urgent warning that the Russia/Ukraine war possessed the potential to reduce Russia’s oil production by ~3 million b/d. This resulted in the IEA calling for a global, coordinated SPR release that ultimately totaled ~260 million bbls.

Not to mention that the UAE will have an equal say in this matter with output reduced by a further ~1.7 million b/d.

Collectively, the Saudis and UAE can structurally reduce production by ~4.7 million b/d, which would send the global economy into a tailspin. By my estimate, crude oil would have to reach $450/bbl to reduce global oil demand by that magnitude. This is not a scenario you want to face over the long run.

In such a scenario, the US would be forced to step back in again. So it’s not whether President Trump wants to exit; it’s ultimately going to be what the regional players want. Because yes, they hold a lot of leverage over the situation, both directly or indirectly.

The Other Big Problem

What about other non-OPEC supplies?

It’s not coming. US shale can flex 1 million b/d at most. The other non-OPEC producers might increase production by ~1 million b/d by 2028. That’s a total of 2 million b/d in supply additions. That’s nothing compared to what the Saudis and UAE can flex on the global oil market at a moment’s notice.

So, from a timing perspective, you have the perfect confluence: no new supply additions + an outage of epic proportions.

Demand destruction via astronomically high oil prices is the only way out of this.

One Step At A Time

The longer-term impact on the oil market will take time to play out. In the meantime, the market is still contending with the daily “TACO” commentary and the frequent misdirection. Most market participants continue to believe that the conflict will be resolved in short order, without realizing that structural issues will remain unresolved for some time. The only “quick” fix I see here is if the Iranian regime is toppled. Outside of this scenario, I don’t see how there’s a smooth resolution. As I explained above, the status quo, a toll fee, is a non-starter for the Gulf Countries.

The oil market will never be the same again, but it will only reach this conclusion one step at a time.

Analyst’s Disclosure: I/we have a beneficial long position in the shares of UCO, USO either through stock ownership, options, or other derivatives.

This is the first time in a decade since I’ve specialized in energy that none of the energy specialists are in disagreement.

First time.

This point is important to understand when analyzing the oil market because in a normal market environment, oil prices are sensitive to small changes to the balance. If you have been building oil supply & demand models as long as I have, you might get disagreements between 0.5 to 1 million b/d at most.

Coming into 2026, IEA had projected a surplus of 4 million b/d, while others projected a surplus of 2 million b/d. This was considered the largest difference in forecasting ever.

Think about that for a second. It’s 2 million b/d; how much can you really argue about here?

A lot, actually. And this is where the generalists just have no idea when it comes to the oil market.

You see, commercial inventories are not really all commercially available. US commercial crude storage has a headline number of 460 million bbls, but it’s not really 460 million bbls. Roughly 135 to 155 million bbls of that is in linefill, volumes needed to keep pipelines flowing. And then you have operational minimums, volumes required to keep storage working.

The reality is that US commercial crude storage has a tank bottom near 370-380 million bbls and has a tank capacity of 540 to 570 million bbls. The margin of 160 to 200 million bbls is all you can play with.

So when you talk about a 2 million b/d surplus, that’s a lot. Over 365 days, that’s a build of 730 million bbls. Without buying from China, this type of surplus can easily push commercial crude storage towards tank tops. This is why during the COVID lockdown, oil prices responded so swiftly to the downside. A 15 million b/d demand outage, coupled with the Saudis launching an oil price war, all but guaranteed that other producers had to shut-in production to prevent storage from hitting max.

And this brings me to the point of this article: none of the energy specialists disagree on the “math” because the deficit is so large; the minuscule details we used to argue over are no longer relevant.

If you miss the current balance by as much as 2 million b/d, you are really not missing all that much. When global oil production shut-in is as high as 13 million b/d, whether it’s 9, 10, or 15 million b/d becomes irrelevant.

Oil market balances are extremely sensitive to imbalances of just 1 million b/d, let alone a supply outage of 12 million b/d. You have to be in the oil market to understand that, and very few generalists appreciate this fact.

So it’s not fear-mongering when everyone in energy is screaming at the top of their lungs that there’s a crisis coming. Because it is what it is.

Heavyweights Agree

There are 3 independent heavyweights in the physical oil trading business: Shell, Vitol, and Trafigura. Combined, the 3 heavyweights trade ~27 to ~28 million barrels per day. In global oil supply terms, they are ~26% of the market.

So when the math of 1 billion bbl supply loss gets validated by both Vitol and Trafigura, you can imagine the smile on my face.

Vitol

Trafigura

And once again, this brings me to my point: there’s never been a point in my career when everyone specializing in energy agrees on the magnitude, while the market disagrees.

This is the first.

Market Implications

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Please read “The Oil Market Breaking Point” article.

In our write-up published on March 25, we outlined a range of scenarios and explained that the oil market’s breaking point would be mid-April. We are now past the breaking point.

From this moment forward, the 11 to 13 million b/d of supply outage will either show up in 1) crude storage draws, 2) product storage draws, or 3) demand destruction.

For those of you not familiar with the logistics or logic of this, let me bring you up to speed.

The oil market breaking point coincided with the last barrels from the Persian Gulf to the end user. Once those tankers offload the barrels onshore, the lack of offloading will start to drain onshore oil inventories. (For additional details on the onshore storage math, please see this write-up.)

At the moment, the global refinery outage is over ~5 million b/d, with ~3 million b/d concentrated in the Middle East. Asia and Europe are both reducing refinery throughput, but just because refineries throttle back doesn’t mean end-user demand is down.

The subsequent reduction in refinery throughput will lead to faster product storage draws, raising petroleum product prices. This cycle will then feed itself back into higher refining margins and, thus, higher refinery throughput.

This cycle will rinse and repeat for a few more weeks:

Elevated crude prices > compressed refining margins > lower refined products > lower product storage > higher refining margins > higher throughput > higher crude prices

On the physical market, you will see this game being played by traders who hold storage and refineries that don’t have storage. This, of course, will only last as long as there is something to draw down in onshore crude storage, but that time is running out soon.

By the first week of May, the only Asian countries with real excess in crude oil inventories will be Japan and China. Everyone else will have to scramble for barrels on the market, and if the Strait of Hormuz remains closed, that’s when you will see refineries pay any price they can to secure the barrels they need. Because the alternative is shutting down the refinery.

For Europe, the lack of crude will become apparent by the same timeframe. US crude exports will have averaged near ~5.5 million b/d by then. OECD crude oil inventories will have reached operational minimum with the remaining excess crude in storage residing in the US.

By our estimate, US commercial crude storage will be below ~400 million bbls and approaching the operational minimum (370 to 380 million bbls) by the end of July. This includes an estimated SPR release total of 139 million bbls.

At some point between now and then, the Trump administration will have to ban both product and crude exports. We suspect that Trump would ban product exports first, and if US refineries start throttling throughput due to a compression in margins, they will ban crude exports after, which would be a disastrous scenario for US shale and Canadian oil producers (more on this in a later write-up).

Everything I just wrote above will play out regardless of what happens to the Strait of Hormuz. Even if the US and Iran reach an agreement to reopen the Strait of Hormuz without conditions, onshore oil inventory draws will materialize.

Rationale Explained Again

Let’s say that by Tuesday, the ceasefire ends with a long-lasting peace deal in place.

There are ~160 million bbls of floating storage in tankers that will rush for the exit. These barrels will take 30-40 days to transit + offload. For these tankers to return, it would take an additional 20 days.

As for the other segments in the market, there are 70 VLCCs headed for the US right now to load US crude and offloading to Asia. The time it takes for these VLCCs to load will be 6-8 weeks. Transit time to Asia will be another 45-50 days. To offload and go back through the Strait of Hormuz would be another 20-25 days. In total, we will not see meaningful tanker traffic back in the Strait of Hormuz from this entourage for at least 3 months.

To alleviate the current onshore storage build-up in the Middle East, we would need at least 100 VLCCs. There are 600 million bbls of onshore storage, and to give producers enough cushion to restart production, onshore storage needs to drain down by ~200 million bbls. Again, tanker activity shows that’s not physically possible until mid-to-late June, at the earliest.

Once the onshore crude storage drains, we need a steady flow of tankers coming to through the Strait of Hormuz to pick up crude. By this point, producers like Saudi, UAE, Kuwait, Qatar, Iraq, and Bahrain can restart. This process will take a few more weeks all but guaranteeing that the lack of supply continues.

Again, by our rough estimate in the March 25 Breaking Point write-up, the cumulative storage lost due to the closure is already ~1 billion bbls. This increases to 1.2 billion bbls by the end of April, 1.59 billion bbls by the end of May, and 1.98 billion bbls by the end of June.

We do not have enough commercially available crude for that much supply loss. This is why demand destruction is needed to prevent such a scenario from materializing.

This is just math.

The Problem With The Geopolitics

I hate geopolitics. It’s unpredictable. There’s no margin of safety. It’s a lot of grey and never black and white. But in the case of the Iran conflict, it seems to be all-or-nothing.

My friend PauloMacro recently recommended Professor Robert Pape, author of the Escalation Trap. And I digested everything he wrote and talked about over the last 2 months. He recently shared a piece titled, “Why the Ceasefire Keeps Failing.” I recommend that you read that.

Now speaking from my experience, what I witnessed this weekend came straight out of a horror film.

Since the conflict began at the end of February, most tankers have chosen to do nothing and wait. There were theories that the Strait of Hormuz was closed due to a lack of insurance. I also shared that view in the early stages of the conflict, but as the events progressed, especially what transpired this weekend, I was shocked.

IRGC physically implemented the closure by threatening tankers with gunfire. We saw this visibly through tanker activity. This is the first time since we started tracking tanker activity that we saw tankers turn around in volume. In the past, we saw maybe 1 or 2 tankers do that, but not in the size it did this weekend.

To me, this signals that 1) IRGC is firmly in control of the Strait of Hormuz and 2) the conflict will need to get worse before it gets better. It is clear from the demands that the IRGC/Iran is making that the US would never agree. So the option is very narrow here, and the only way to solve this issue in the long run is to “solve” it if you understand what I’m saying. I fear the worst has yet to come, and I don’t say this lightly.

Oil Market Scenarios

In our previous article on the oil market’s breaking point, we explained that if the Strait of Hormuz opens by the end of April, Brent will “drop down” to $110/bbl; it’s trading at $95 today.

As I already explained, the oil market has passed the breaking point. The onslaught of oil inventory draws coming will shock the market awake. I suspect that only when financial players see the physical shortages playing out will they wake up to the reality that this supply outage is real. Until then, most people will not be able to accept the reality.

It is what it is.

If the Strait of Hormuz opens after April, we cannot provide an accurate oil price forecast. We will have crossed too deep into the Rubicon. This will have been the largest oil supply outage in the history of the oil market by a magnitude of 4x. Fundamental market theories will no longer apply here because there’s no price for outright shortages. When a market runs out of fuel, it just runs out.

What does that last marginal barrel trade for? I have no idea, and I don’t think anyone will be smart enough to know the answer.

What I do know is that demand destruction is coming, and for oil watchers, policy announcements will be what “kills” demand. To balance ~11 to ~13 million b/d of global supply outage, we need the same magnitude of demand loss as during the mandated COVID lockdowns.

And even in that dire scenario, the market will be “balanced” and not in surplus. But it will have dampened the impact on price, and the barrel counters, including myself, will know when the inflection point (fundamentally speaking) is here.

So if you want a short summary:

• I have no idea what happens to oil prices if the Strait of Hormuz stays closed past April, but it’s not $95/bbl.

• Policy-mandated demand destruction will rebalance the oil market, but only keep storage from declining further.

• We have developed market signals in place to watch for this turning point when it comes.

Conclusion

The oil market breaking point is here. Global onshore oil inventories are going to plummet, and the decline will be at a pace no one has ever seen before. US oil inventories were the last to start declining, and we will see it in next week’s EIA oil storage report. Once the market sees the visible onshore inventory draws, prices will quickly inflect.

If the Strait of Hormuz remains closed past April, no one will be able to tell you where oil prices top out. We will have gone too far into the Rubicon. Oil demand destruction will be the only way to rebalance the price, so instead of fixating on “price”, we need to follow the signals.

But if there’s anything you can take away from this article, it’s this:

The oil market won’t rebalance at $95 per barrel. Oil prices will have to reach a level high enough to offset ~11 to ~13 million b/d of supply outage. Governments will have to mandate COVID-like demand reduction policies to depress demand. Even then, it will have only offset the supply outage and not pushed the oil market into surplus. On the geopolitical side, I fear that we have entered a phase of “getting worse before it gets better,” as both sides (the US and Iran) appear not to budge.

On the investing side, I put my money where my mouth is.

Here are the following trade alerts we published to paid subscribers:

Long BNO call option

Long USO and UCO

Long USO and UCO

Analyst’s Disclosure: I/we have a beneficial long position in the shares of USO, UCO, BNO call options, USO call options either through stock ownership, options, or other derivatives.

Long USO May $135, $145 strike calls.

Long USO May $215-$245 call spreads.

Long USO June $125 calls.

Long BNO July $50 and $60 calls.

My advice to you is simple: follow the signal.

As I’ve said recently, the math is what it is. Generalists can believe whatever headline or narrative that’s being touted, but oil inventories will decline. Whether they will only believe it when it “shows up” or whatever is up to them. I’m not here to hold the market’s hand. I’m here to make money.

Where are we on the oil storage math?

As I’ve been saying since the start of March, the excess oil-on-water drained first. This is gone now.

There’s a minimum volume required for oil-in-transit. So you should not expect this to nosedive any further unless the Strait of Hormuz remains closed until the end of May.

Onshore crude oil inventories are starting to follow suit.

On the surface, this looks like we are still in surplus, but that’s not really the case.

China holds the entire surplus in storage. As I’ve said, this is a national security concern, so China will continue to hoard crude and ban product exports. The product export ban has jacked up Asian refining margins, and sadly, that’s still not enough. Without those teapot refinery product exports, Asia will run low on products in 3 weeks.

As for the rest of the world, the onslaught of the draws is about to hit storage with full force.

Even if the Strait of Hormuz opens this very second, the draws will continue until August. There’s nothing anyone can do about that at this point. The math is what it is.

What about crude exports?

Global crude exports are down ~9 million b/d y-o-y. The data is now confirming all of the math the oil specialists have done over the last month.

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Long 1,500 BNO $60 strike calls at $3.45 July 17, 2026 expiry in the HFI Portfolio.

This is a conviction bet position for us.

Rationale:

Backwardation roll yield in Brent futures offer BNO a natural upside return over the coming months. BNO is currently in June futures with rolls to July contracts expected soon.

June Brent is trading at $99.57 wh…

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If you had traveled back in time and told me the following:

• Iran, the US, and Israel are at war.

• The Strait of Hormuz is “effectively” closed with ~11 million b/d of crude oil production shut-in.

• Global SPR release of 400 million bbls.

• Cumulative production lost to date totalling 400 million bbls.

First of all, I wouldn’t have believed you. Second, this kind of scenario is what you write in science fiction novels. Finally, if you had told me that June WTI contracts would be trading at ~$88/bbl and Brent would be at $95/bbl, I would’ve laughed.

Yet here we are.

I think all the energy specialists out there are trying to make sense of the disconnect between oil prices and fundamentals. Remember that in our “Oil Market Breaking Point“ article, we made the point that jawboning will work until it doesn’t. There’s a certain point in the oil market that once you cross it, it’s hard to go back. The reason for this is the cumulative storage lost even in a reopening scenario.

From a narrative standpoint, I don’t think energy specialists have to look very far to understand why the market still doesn’t care about the shortages that are coming. US commercial crude storage remains bloated, with no signs of large draws until early May. The Trump administration is making it incredibly difficult for traders to put on long positions with each headline having the possibility of jolting oil prices lower.

But the math is what it is. Production shut-in is barrels that will be replaced via lower storage elsewhere. The longer prices are kept suppressed, the longer it will take for the eventual rebalancing to happen. What the market is failing to realize is that by not signaling early demand destruction, it ultimately magnifies the impact down the road.

Inflection Point

Over the past few hours, I’ve reached out to a few very smart oil traders. I only had two questions:

• Where am I wrong?

• What am I missing?

One trader brought up something that I should’ve known better: the generalists don’t care until onshore inventories start to plummet.

When I first wrote the breaking point article, I was thinking along the lines of “when is the last tanker arriving at its final destination from the Persian Gulf?”

Well, the reasoning behind that was that you want to find the starting point for when onshore inventories start to plummet. I figured the oil market should be able to extrapolate the implied balance forward and price into oil to prevent a tank bottom scenario.

Oops, I guess I was wrong on that.

So was I wrong in saying that global onshore inventories won’t plummet now?

No, and I have yet to find anyone who can prove the math otherwise. Again, the math is what it is.

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We have a lot of ground to cover in this update. Here’s what happened this weekend:

• US and Iran failed to reach a peace agreement.

• President Trump announced today that the US Navy will form a blockade to prevent Iranian ships from passing through the Strait of Hormuz.

Anyone who reasonably expected Iran and US to reach a peace settlement at a meeting over the weekend must not have studied the previous Nuclear Deal signed into place under President Obama. The Iranians are infamous for being tough negotiators, and with the Strait of Hormuz traffic under their control (for now), they will push this advantage to the end.

As for the negotiation, there were 3 sticking points that will continue to pose as major issues going forward:

• The US rejected any notion of a toll fee arrangement from the Iranians and demanded that the Strait of Hormuz be reopened immediately. Again, we have discussed this in depth in this write-up. The notion of a toll fee arrangement is a non-starter for the GCC. Yes, you can have a gradual reopening, which prevents shut-in production from returning, but you cannot have a gradual reopening with a toll fee.

• The US demanded that the Iranians hand over or sell their entire stockpile of near-bomb-grade enriched uranium. No agreement on that front.

• The Iranians demanded that $27 billion in frozen revenue held abroad be released. In addition, Iran sought reparations for damages.

In my view, the Strait of Hormuz issue will be the biggest sticking point going forward. As I’ve written numerous times, the bogeyman is out; the Iranians have now played their ultimate trump card. To relinquish this advantage is to admit permanent defeat in the future. This is one bridge they will not cross, no matter what.

For the US, the move to blockade traffic in the Strait of Hormuz will be difficult to execute. We have more questions than answers at this point, so let’s dig deeper.

Impact on the Oil Market

On the blockade, here are some questions we have that will need to be answered:

• What is the enforcement mechanism if the vessel conveys a different destination? GPS spoofing is common knowledge amongst the shadowfleet tankers. Is the US Navy just going to stop every vessel that’s currently on the sanction list?

• Will the blockade cover the Jask terminal, where Iranians can divert crude oil production from Kharg Island? If so, how will the US Navy respond to ground forces launching missiles and drones at the ships?

• Will the US Navy get into a confrontation with Chinese vessels? If so, what are the ramifications there?

For the oil market, here are some of the facts:

• Iran currently has ~170 million bbls in floating storage/oil-in-transit. Despite the US lifting sanctions on Iranian exports, Iran has been slowly depleting this stockpile. At $135 per barrel (physical market prices), Iran’s floating storage is worth $22.95 billion. This will buy it some time to deal with the blockade (assuming it’s effective).

• The US blockade, if effective, would choke off Iran’s crude export, which is estimated to be ~1.6 to ~2 million b/d. This would increase the global oil supply outage to 12.6-13 million b/d.

Another important ramification for the global oil market is that the Bab el-Mandeb Strait, which is responsible for Saudi’s entire crude export volume from Yanbu today (4.5 to 5 million b/d), could be disrupted by the Houthis. If this chokepoint develops, global supply would be out by 17 to 18 million b/d.

At this point, the oil math is impossible to fathom. The scale of the supply disruption is the equivalent of the demand disruption we saw at the peak of COVID. To balance the global oil market, prices will need to reach a level that matches the level of activity reduction we saw in 2020.

At some point over the coming weeks, countries with insufficient storage capacity will have to impose the same degree of lockdowns. This is when the physical oil market will escape reality and enter into fantasy land.

I suspect in the coming weeks, sellside analysts will have to start asking the question: how high do oil prices have to go to balance ~13 million b/d of supply disruption?

Note: Please read our article: Oil Demand Destruction Is Coming, It’s Too Little Too Late.

It’s anyone’s guess now, but I can tell you this with confidence: it’s not $150/bbl, it will have to be a lot higher.

Why aren’t oil prices higher?

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Selling all of Tronox and Kronos.

Sell all of TROX at $9.16 for a gain of ~145.5%.

Sell all of KRO at $6.61 for a gain of ~33%.

Reasoning:

Our oil market view is that demand destruction is coming. Economically sensitive names like TROX and KRO will be negatively impacted. Names like Chemours will be partially insulated due to the refrigerant busi…

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We have three high conviction views on the oil market today. These are:

• If the Strait of Hormuz does not return to normal, oil demand destruction via materially higher prices will rebalance the market.

• If the Strait of Hormuz returns to normal this very second, production shut-in (~11 million b/d) will not return to normal until the end of June at the earliest.

• If Iran imposes a toll fee arrangement, Saudi Arabia and the UAE will continue to bypass crude exports via the East-to-West and Abu Dhabi pipeline. This will keep ~4.7 million b/d offline. Here’s our explanation for why.

In our public write-up published on Tuesday titled, “The US And Iran Ceasefire And What It Does To The Oil Market.” We explained in detail the math behind our conviction point #2 above. The market’s problem going forward is that, with each passing day, there’s no complete resolution to the Strait of Hormuz or the production shut-in, onshore storage is falling.

Using the latest tanker-tracking data, this is our updated estimate of US commercial crude storage by the end of June.

Tanker activity shows that US crude exports are about to explode past ~5 million b/d. This explains, in part, why Brent-WTI spreads have started to meaningfully collapse.

Once US commercial crude storage falls close to ~400 million bbls, Cushing will have reached close to operational minimum. This is when we will see WTI timespreads explode. We are already seeing Brent physical prices gap $30+ higher, and it’s only a matter of time before financial markets catch up to the physical reality. There won’t be any market manipulation attempts there when we run out of the onshore inventory cushion.

All of this leads us to believe that the only way the market can effectively balance everything is via demand destruction. So what are the signals?

Signals

Refining Margins

The first and most obvious signal for demand destruction will be when global refining margins turn negative. We all know that the majority of the supply outage today is in crude. There are ~11 to ~13 million b/d of production shut-in that won’t return anytime soon (logistical timing). To grasp the intensity of the supply outage, just imagine that during the height of the pandemic lockdown, global oil demand fell by ~10 to ~15 million b/d.

In other words, if the global economy returns to COVID-style lockdowns, you “might” be able to balance the current supply outage.

To get a sense of how all of this will unfold, we just have to use historical examples to grasp the timing and nuances of events.

Let’s use COVID as an example. Here is the sequence of events:

• Lockdown imposed.

• Staying home mandated.

• Product inventories build.

• Refineries cut throughput.

• Crude inventory builds.

• Floating storage builds.

• Prices drop below the operating breakeven.

• Production shut-in.

Those were the initial steps; the rebalancing looked like this:

• Lockdowns ease.

• Mobility indices increase.

• Product inventories decrease.

• Refining margins rebound.

• Refinery throughput increase.

• Crude inventory stops building.

• Floating storage starts to decline.

• Prices recover back above the operating breakeven.

• Production shut-in gradually returns.

Now that you understand the logic chain, here is what’s happening today.

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By: Jon Costello

Mach Natural Resources LP (MNR) sold off by more than 10% on Tuesday after pricing a 9-million-unit secondary offering at $13.05 per unit. By today’s close, the units continue to trade nearly 6% below the offering price. The units’ selloff in response to the news is silly, and it presents an opportunity for long-term investors willing to look past the headline.

The Secondary Is Not What The Market Thinks

On April 6, three selling unitholders, Vepu Inc., Simlog Inc., and Sabinal Energy Operating LLC, priced a secondary offering of 9 million common units, with Morgan Stanley serving as the bookrunner. The sellers also granted a 30-day greenshoe option for an additional 1.35 million units.

The units’ selloff suggests the secondary offering is significantly dilutive to common unitholders, even though Mach is not issuing a single new unit and the company will not receive any proceeds from the offering. Only existing units are being sold, which are already counted in Mach’s 168 million units outstanding. These units are already reflected in every per-unit financial metric.

In short, the secondary is a large unitholder liquidity event, not a capital raise. Nothing about the economics of Mach’s business has changed as a result of this offering.

As a longtime investor in MLPs, this activity in the units comes as no surprise. I’ve seen many sponsor-backed midstream entities go through a predictable cycle that begins with early investors holding large blocks of common units, which suppresses the units’ trading multiple. The market then treats every secondary offering as a negative signal. Eventually, the overhang clears and the unit price re-rates to higher levels. Hess Midstream (HESM), another longtime holding of ours, has experienced such a cycle.

Mach units’ response to this secondary strikes me as similar. The unit price has declined even though the secondary had no dilutive effect, while bringing benefits such as increased public float, improved daily trading liquidity, and, arguably, an improved unitholder base. All these factors are long-term positives, not a reason to sell.

Resilience Amid a Brutal Selloff

I bought Mach units on Tuesday at an average cost of $12.69 per unit. The days that followed the purchase have provided an unexpected but instructive test of Mach’s downside resilience. Wednesday’s session was the worst day for the energy sector in a year. The SPDR S&P Oil & Gas E&P ETF (XOP) fell 6.3%, Diamondback Energy (FANG) dropped 7%, Occidental Petroleum (OXY) fell 7%, and APA Corporation (APA) lost more than 9%. The trigger for the selloff was the announcement of a conditional ceasefire and the potential reopening of the Strait of Hormuz, which sent WTI crude tumbling from above $112 per barrel to the mid-$90s in a single session as the market rushed to unwind the war premium.

Against that backdrop, after the headwind from Mach’s secondary offering, its units have declined only 2.7% since my purchase. Their relative resilience reflects the excessive selling that occurred on Tuesday, as well as their status as an unloved MLP. But I believe it also reflects the nature of Mach’s asset base, which consists of long-lived, low-decline wells across the Anadarko and San Juan Basins. The company’s low cost structure enables it to generate free cash flow at virtually any oil price above $40 per barrel, so Mach isn’t likely to get dragged down as violently as operators running on the treadmill of high-decline Permian shale with higher breakeven costs per barrel. Its business resilience translates into resilience in its unit price, particularly when that price is as discounted as it is today.

Mach’s Valuation Disconnect

At our $12.69-per-unit purchase price, Mach’s enterprise value stands at approximately $3.2 billion, comprised of its roughly $2.2 billion market capitalization and $1.1 billion in net debt. At year-end 2025, Mach reported total proved reserves of 705 million barrels of oil equivalent, representing a 109% year-over-year increase, with a PV-10 value of $3.1 billion. The PV-10 alone covers nearly the entire enterprise value, implying that the market assigns essentially zero value to owned midstream infrastructure, future development upside, and continued growth through future accretive acquisitions.

Consider that under current management, Mach has never acquired an asset at a price in excess of PDP PV-10. When management consistently buys oil and gas assets below their intrinsic value at low commodity prices, and commodity prices then increase while the market value remains flat, the gap between market price and asset value becomes a coiled spring. In today’s commodity environment, the spring is very tightly coiled.

Mach’s valuation gap widens further when measured against corporate E&P peers. Mach trades at approximately 4.4x EV/EBITDA. At first glance, that looks to be in line with some C-corp peers, such as Devon Energy (DVN), at 4.7x. But Mach is a master limited partnership, which requires K-1 tax forms, multi-state filing obligations, and disqualification from most tax-advantaged retirement accounts. Many institutional investors cannot or will not hold MLPs. The more limited universe of potential buyers structurally depresses the unit price relative to what the same assets would command inside a C-corp, creating a sort of “form-over-substance” penalty that has nothing to do with the quality of the business.

Moreover, Mach’s EV/EBITDA multiple is significantly lower than Diamondback (FANG) at 6.0x, EOG Resources (EOG) at 6.0x, and ConocoPhillips (COP) at 6.9x. Investors can purchase Mach at a 25% discount from these names.

The yield differential tells the story. Mach yields significantly more than 10% at current prices. Meanwhile, Devon yields roughly 1.8%, EOG yields 2.9%, and ConocoPhillips yields 2.6%. Investors can therefore buy Mach at a lower multiple and receive three to five times the cash distribution. When its units’ overhang eventually clears through either secondaries reducing the sponsor’s stake, a potential C-corp conversion, and/or simply the passage of time, the re-rating potential is far greater than that of a comparably valued C-corp.

Mach offers relatively greater downside protection in a prolonged crude price disruption. Its variable distribution model means distributions ramp directly with oil prices, unlike peers whose capital allocation is weighted toward buybacks and fixed dividends. If crude falls sharply, Mach’s $10.72 per Boe cash operating cost and 17% corporate decline rate provide a wider margin of safety than Permian E&Ps with cash operating costs at $15 to $20 per Boe with 30% to 40% declines. In either direction, Mach is better positioned than its multiple suggests.

And deleveraging will accelerate, as every dollar of incremental cash flow from elevated commodity prices flows through to debt reduction, shortening the time to achieve to management’s 1.0x leverage target. The company will emerge from this episode prepared for its next phase of acquisitive and opportunistic growth, which I expect will come once commodity prices have fallen to lower levels.

The Distribution Engine

In 2025, Mach paid $1.97 per unit in total cash distributions, representing a yield of 16% at Mach’s current unit price. The fourth-quarter 2025 distribution was $0.53 per unit, which was paid on March 12, 2026.

Mach’s capital allocation plan stipulates that no more than 50% of operating cash flow is to be reinvested in the company’s development capital, with the remaining capital distributed to unitholders. For 2026, management has guided to $315 to $360 million in total development capital against a production target of 150 to 157 MBoe/d. That reinvestment ceiling is a structural feature of how the company operates. It creates a floor under distributions that doesn’t depend on management’s discretion in any given quarter.

My fourth-quarter 2025 earnings review, published on March 17, walked through the distribution math under an $82.50-per-barrel WTI scenario. It is worth revisiting, as the conclusion remains the same and the commodity environment has only improved since then.

At $82.50 per barrel WTI, we estimate that Mach’s quarterly distribution could rise from approximately $0.53 to approximately $0.74 per unit, representing a 40% increase, driven primarily by the revenue uplift on unhedged production volumes net of roughly $59 million in annual hedge settlement losses. Annualized, that implies approximately $2.96 per unit, or a yield approaching 20% at a $15 unit price. With WTI currently trading around $100 per barrel, the actual upside is even more pronounced, though Mach’s hedge book, which included 3,436 MBbl in fixed-price swaps at $66.13 per barrel and 549 MBbl in costless collars with a $78.05 per barrel ceiling, caps some of the near-term benefit. The point is not that $0.74 is a precise forecast. It is that the distribution’s sensitivity to oil prices is substantial, and the current price environment is extremely favorable for unitholders.

Balance Sheet and Path to Deleveraging

Net debt of approximately $1.1 billion against pro forma trailing-twelve-month adjusted EBITDA puts its leverage ratio at roughly 1.3x as of the end of last year. Management has been clear about its priority to return to 1.0x leverage before pursuing further acquisitions. With $338 million of available liquidity under a $1.0 billion revolving credit facility, Mach’s balance sheet is not stressed.

The deleveraging path and the distribution are funded by the same cash flows. The capital allocation framework accommodates both without forcing a trade-off, and every quarter of execution brings leverage closer to management’s target.

Catalysts on the Horizon

The next potential inflection point for Mach units is the company’s first-quarter 2026 earnings, expected in May. This will be the market’s first clean look at production and cash flow tracking against the 150 to 157 MBoe/d guidance and the company’s new capital plan.

Meanwhile, management’s development of the Mancos shale in the San Juan Basin, which CEO Tom Ward has called a “world-class reservoir,” adds optionality that is not priced in. If those results continue to outperform, the reserve and production trajectory has meaningful upside beyond current guidance.

Later in the year, I expect improved financial results to be another catalyst from Mach’s current stock price. Mach’s multi-basin position across the Anadarko and San Juan Basins, consisting of more than 10,000 net producing wells on long-life, low-decline assets, generates ample cash in low-commodity-price environments, but is a cash machine at higher commodity prices like today’s. The market will have a better grasp of Mach’s cash generation potential over the coming quarters, which I expect will bolster distributions and drive the units higher.

Conclusion

My approach to a position like Mach in the HFIR Energy Income Portfolio is the same as for Genesis Energy LP (GEL) and other income-oriented holdings. I aim to manage the portfolio conservatively, prioritizing income safety over trying to goose returns by timing commodity cycles or holding out for a few extra points of upside. Once my return parameters are met, I consider selling. The goal is steady, compounding income, not heroics. Mach’s deeply discounted units, low cost structure, and unitholder-friendly distribution framework are built for exactly this kind of patient, income-first approach.

At $12.69, we’re buying a vehicle that is yielding significantly more than 10% based on oil prices we expect to prevail this year, backed by $3.1 billion of proved reserves calculated at lower oil prices, run by a management team with a consistent track record of capital discipline with a clear path to deleveraging and multiple upcoming catalysts. The MLP discount that compresses Mach’s multiple relative to corporate E&P peers is a gift to investors willing to put up with the hassle of a K-1 at tax time. When the unit overhang clears, Mach’s re-rating potential is far greater than what Devon or EOG offer from current levels.

Mach’s secondary offering changed nothing about the business. It moved existing units from one set of hands to another. The 10% selloff it triggered is a gift. Investors interested in both income and capital appreciation should consider buying the units at a bargain price below $13.

Analyst’s Disclosure: Jon Costello has a beneficial long position in the shares of MNR, GEL, HESM either through stock ownership, options, or other derivatives.

Buying more USO and UCO for the HFIR Oil Trading Portfolio.

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WTI and Brent, as of this writing, are down ~14%. The US and Iran agreed to a 2-week ceasefire pending “safe passage” through the Strait of Hormuz. Ahead of the Friday talks, these are the 10 points Iran has presented to the US:

1. Commitment to non-aggression.

2. Continuation of Iran’s control over the Strait of Hormuz.

3. Acceptance of uranium enrichment.

4. Lifting of all primary sanctions.

5. Lifting of all secondary sanctions.

6. Termination of all UN Security Council resolutions.

7. Termination of all Board of Governors resolutions.

8. Payment of compensation to Iran.

9. Withdrawal of U.S. combat forces from the region.

10. Cessation of war on all fronts, including against Hezbollah in Lebanon.

Over the next few days, I’m certain you will read a lot of takes on whether the US will actually agree to any of these points, but from my perspective, I will just offer you my analysis on the energy-related side of things.

On the Strait of Hormuz front, Iran’s Foreign Minister, Seyed Abbas Araghchi, wrote on X (related to the Strait):

For a period of two weeks, safe passage through the Strait of Hormuz will be possible via coordination with Iran’s Armed Forces and with due consideration of technical limitations.

With that, let’s get started.

Implications on Oil

There are currently ~180 million bbls of stranded floating storage in the Persian Gulf. This temporary ceasefire unlocks these barrels. The short-term impact, oil selling off, is in part related to these barrels becoming available on the physical market.

Now there are still more questions than answers. For starters, will Iran charge a toll fee? If so, how much?

We don’t know the answer to that, but let’s assume some producers accept this toll arrangement. Iraq needs the tankers offloaded, as it is the most severely affected by the current Strait closure. But even though tankers are able to exit the Strait of Hormuz, you need empty tankers to travel in to load additional crude.

In addition, the empty tankers will have to first drain the onshore storage built up before producers can restart production. For Iraq, 2-weeks is far from adequate to restart production. There are also no guarantees that the Strait will remain open after 2-weeks. Given that Iraq sells on a free on board (FOB) basis, where the buyer assumes all transportation, insurance, and freight risks once the crude is loaded on the tanker, I don’t think anyone will take the risk of being stuck in the Strait again.

In essence, the ceasefire does not change the production shut-in math. The current production shut-in of ~11 million b/d will continue.

On the toll arrangement front, if Iran implements a toll fee arrangement, I fear we have not yet seen the worst for the global oil market. As we explained in this WCTW piece titled, “The Unacceptable Status Quo And Why The Oil Market Will Never Be The Same Again.” The Saudis will never accept the toll fee arrangement.

Both the Saudis and the UAE would rather divert crude exports via the East-to-West and Abu Dhabi pipelines than pay a toll to Iran. This is primarily due to the power dynamics of controlling your own destiny (crude production/export). If Iran is allowed to impose a toll fee, it will effectively have a say in future exports out of the Gulf. That’s a non-starter for the Saudis and UAE. This is an existential crisis, so it would rather keep production shut-in than play the game.

The Math

Because the ceasefire doesn’t change the production shut-in figures, total barrels lost will remain the same through this 2-week stretch.

Even if we assume that ~180 million bbls are unlocked, it buys the world an additional 16 days. But the timing mismatch will be problematic. Even if all the tankers make it out tomorrow, it will take 30-45 days to reach their destination and discharge. India benefits here, given the close proximity to the Strait, but countries like China, which will absorb all the excess for SPR, will have to wait closer to 45 days.

OECD commercial crude oil inventories have a cushion of ~178 million bbls. SPR release rate in April will total ~75 million bbls (253 million bbls). Given that the production shut-in math for April points to ~330 million bbls, the breaking point for the oil market is already too little too late.

If we assume that the two sides reach a permanent ceasefire agreement in 2 weeks, total oil inventories lost due to the closure will be around 1.2 billion bbls. We will have exhausted the OECD operational cushion for crude by the end of April, and the reality is that we will be facing a physical crude shortage.

Here’s the math we explained in our WCTW write-up yesterday titled, “All Roads Lead To Structurally Higher Oil Prices.”

Let’s use the April 30 ceasefire as an example:

Crude oil production shut-in volumes lost total ~600 million bbls between March and April.

Tanker traffic flow resumes. Tankers stuck in the Persian Gulf start to leave to discharge oil. This will take 35-45 days.

Tankers that received the green light to return to the Persian Gulf have begun transiting. This will take another 35-45 days from travel time to loading.

In the meantime, production shut-in continues. That’s another 30 days, at minimum, or another ~330 million bbls.

Once the tankers arrive to load crude, onshore oil inventories must be drained first; this will take 7-10 days before production can restart. That’s another 70 million bbls.

That puts the production loss total AFTER the Strait reopens at ~400 million bbls.

Production restart will take a few weeks to get back to normal. Assuming that production is operated at half capacity, that’s an additional ~120 to ~140 million bbls of outage. That puts the total now at ~520 to ~540 million bbls AFTER the Strait is open.

Total production outage, even with the Strait of Hormuz opening by April 30, is 1.12 to 1.14 billion bbls, and that assumes no product outage. We are just assuming here that the product outage is offset by demand loss elsewhere.

So why will oil prices remain structurally higher?

As I explained above, the OECD commercial crude oil inventory has an operational capacity of 178 million bbls. Total SPR release is 400 million bbls. That puts the total available capacity at 578 million bbls. IEA will need to release an additional ~700 million bbls to offset the scenario we outlined above.

Given that SPR also has a minimum stock requirement, effective spare capacity is around ~800 million bbls. In essence, if we completely drain the global SPR, we will simply offset the production loss if the Strait of Hormuz returns to normal by the end of April.

So yes, this ceasefire doesn’t change anything.

Problematic

For the oil market, we can jawbone financial oil prices a while longer. US commercial crude inventories are the last to decline. US inventories, as we explained yesterday, will be insulated, unlike those in other regions of the world. But as onshore inventories start to decline now, US crude imports will drop, while US crude exports will spike.

Here’s an illustration of the current tanker flows headed for the US by the first week of May, irrespective of what happens to the Strait of Hormuz:

At some point, the cushion in US commercial crude storage, ~80 million bbls, will also give way to a shortage. US SPR release will help dampen some of the incoming draws, but we are really just transferring the SPR release to other regions of the world.

The crude shortage will first translate into lower refining margins and then negative refining margins. Demand destruction is the only way to balance the shortages we will see.

Conclusion

I hope this article was helpful in explaining the nuances of the ceasefire on the oil market. The logistical jam will prevent production shut-in from returning. Meanwhile, the Persian Gulf will first require many tankers to drain onshore storage, and only when there’s a steady flow of tankers will production shut-in return. You can’t just start production and shut-in production a week later. That’s not how any of this works (physically).

Meanwhile, the current crude shortages will eat into the last remaining OECD onshore crude inventories. Once US oil inventories start to show meaningful draws, I suspect that’s when the tipping point for oil prices comes.

Analyst’s Disclosure: I/we have a beneficial long position in the shares of USO, UCO either through stock ownership, options, or other derivatives.

What does structurally higher for longer look like?

It is dependent on the resolution of the current conflict. With each passing day, the world is losing 11 million bbls of crude oil. The math of the supply outage is straightforward:

• April 30 ceasefire: 1.2 billion bbls of crude + product lost

• May 31 ceasefire: 1.5 billion bbls

• June 30 ceasefire: 1.8 billion bbls

This is a rough estimate, as the oil price in the near term will have to reach a level that triggers demand destruction before we get to the May or June scenario. Available commercial crude oil inventories are much lower than people think.

Commercial Storage Math

Here’s a good illustration of this:

US commercial crude oil storage is expected to reach ~435 million bbls by the end of June, regardless of whether the Strait of Hormuz is open or closed. The US does not import a meaningful amount of crude from the Middle East, so the impact is second-order in nature. Instead, US oil inventories would look like this: crude and product imports will decline as they are diverted to other regions, and US crude and product exports will spike.

In essence, the US will be the last place to draw down inventories.

For US commercial crude storage, we can not go below ~400 million bbls. Linefill, volumes required to operate pipelines, and operational minimums require that US commercial crude storage hold at least ~380 million bbls. From June onward, that leaves us with a cushion of ~55 million bbls. The good news is that the US is releasing SPR, so most of it will be exported, and that will dampen the impact of the decline in commercial crude storage.

JP Morgan estimated the operational minimum for OECD commercial crude oil inventories at ~842 million bbls. As of March 2026, we had ~1.02 billion bbls. This puts the effective capacity at 178 million bbls.

Now here’s the math:

IEA announced a ~400 million bbl SPR release.

Daily release volume: 2.5 million b/d.

April, May, and June volumes total 227.5 million bbls.

Effective capacity 178 million bbls + 227.5 million bbls = 405.5 million bbls

Outage from the Strait of Hormuz is 11 million b/d.

April outage is 330 million bbls. SPR release is only 75 million bbls. Net outage is 255 million bbls. We will have already eaten through the effective capacity of 178 million bbls.

This is why the oil market’s breaking point is this month, not in May or June as some analysts expect.

Structurally Higher For Longer

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Source: CommodityWxGroup

Interestingly enough, despite the very bearish heating demand projections, US natural gas storage is expected to remain around the 5-year average going forward due to tight supply and demand balances.

Editor’s Note: Free subscribers can use the 1-time unlock feature to read this piece.

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What we are witnessing with the Strait of Hormuz today is a once-in-a-lifetime type of event. I’ve always pondered how a nobody like myself got involved in energy and lived through 2 “once-in-a-lifetime” events in the span of 6 years: COVID and the Strait of Hormuz closure.

It’s a bit surreal to have built expertise in an area of the market that no one really cared about until... 4 weeks ago. The funny thing is that all the work we’ve put into grinding it over the last 10 years in this sector is starting to pay dividends now. Like the quote from Jacob A. Riis:

When nothing seems to help, I go and look at a stonecutter hammering away at his rock, perhaps a hundred times without as much as a crack showing in it. Yet at the hundred and first blow it will split in two, and I know it was not that last blow that did it, but all that had gone before.

With that, let’s dive straight into this week’s WCTW.

The Unacceptable Status Quo

I’ve read a lot of commentaries from very smart people about what the eventual resolution might look like. One of the more interesting “scenarios” I’ve seen goes something like this:

The Trump administration says that the mission is done and leaves the region, while the Iranian continues to control the Strait of Hormuz flow. Some type of toll arrangement will be in place.

I am here to tell you that it’s a non-starter.

To most outside observers, the logic is straightforward. A VLCC (very large crude carrier) carrying ~2 million bbls of crude oil, worth north of $200 million, should easily afford a toll fee of $2 million. The generalists argue that it’s just $1/bbl, a fraction of the cost of oil. But the misunderstanding is not in the economics of the toll fee, but in the ability to impose restrictions on the potential flow.

To better understand why the status quo is unacceptable, generalists should take the time to research OPEC’s history more extensively. In particular, with the help of Claude or ChatGPT, I implore you to understand why it is so hard for OPEC or OPEC+ to come to a production cut agreement.

From the outside view, OPEC, spearheaded by the Saudis, has every incentive to keep oil prices in a tight trading range. It has already formed a “cartel”, and so in theory, enforcing the production policies should be very straightforward. The logic is that if every producer in the cartel cuts production by 5%, everyone’s revenue goes up by 25%. Win, win, right?

Wrong, and that’s the issue with generalists in energy. Most people use the logical approach when the reality has nothing to do with logic.

The best example of this irrational behavior unfolded in March 2020 when the Saudis asked Russia for an additional 300k b/d cut.

Prior to March 2020, Russia was already responsible for ~300k b/d, so the additional 300k b/d would put the total production cut at 600k b/d. Russia refused to cut the additional ~300k b/d, despite it only being less than ~3% of its total production volume. What did the Saudis do? They unleashed hell.

Saudis took the view that if you aren’t willing to cut production, then everyone can feel the wrath. So instead of coming to the logical conclusion that the demand destruction from mandated lockdowns would inevitably reduce everyone’s oil production, Saudis forced the widespread sector shut-in that was to be infamous with the COVID fallout. A month and a half later? WTI went negative.

The moral of the story is that logic doesn’t drive policies, especially not in the oil market. Consider that if Iran implemented a toll fee, no matter how low it is, it would have an effective say in the flow of Gulf state traffic going forward. This is more powerful and effective than Saudi’s dominant role as the swing producer.

This is why, in my strong opinion, the Saudis would rather keep oil production shut-in by ~3 million b/d than to transport through the Strait of Hormuz. The ramifications are profound.

It Will Never Be The Same

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By: Jon Costello

There is clearly no shortage of Hormuz commentary right now. In making my own contribution, I feel a bit like the author of a self-help book who has to justify his addition to an already oversaturated genre. What I can offer is an article focused on supply math. Most commentary focuses on the geopolitics, such as who said what, which side might blink first, or what an off-ramp might look like. Many fall into the trap of estimating resolution timelines and then pricing backward from that assumption. In this article, I examine the physical market disruptions and their implications for oil and refined product prices.

What becomes obvious is that the market is too complacent about the Strait of Hormuz.

This is not a geopolitical call; rather, it’s implied by the supply math. Regardless of the diplomatic signaling of the moment, the physical supply deficit and logistical realities dictate that this disruption extends through April at minimum, with the likelihood of refined product shortages the longer it persists. Such shortages increase the risk of price spikes, which in turn reduce end-user demand.

At present, I believe the contrarian move is to exercise caution amid what I view as heightened risk. This appears to me to be the best course. Investors should consider adopting a more defensive posture with at least a portion of their portfolio in the event that conditions deteriorate from here. They should be careful not to concentrate too heavily in stocks that require economic growth or low interest rates to support their prices. Defensive positioning can help mitigate the adverse financial and psychological impact of a prolonged energy crisis.

The Supply Deficit Is Larger Than the Headlines Suggest

Before the current disruption, the Strait of Hormuz carried approximately 20 million barrels per day of total petroleum liquids, equivalent to roughly 20% of global petroleum liquids consumption, according to the EIA. Real-time physical market tracking by commodities and shipping trackers puts the supply outage figure at 12.5 to 13.0 million barrels per day (bpd). I am using 12 million bpd as my anchor for this analysis.

Going country by country, the damage is severe. The key question relates to how much of the crude that cannot pass through the Strait has other outlets. From there, it is possible to estimate the net supply outages.

Saudi Arabia cannot export oil through the Strait, so it activated its East-West Pipeline, which carries a 7 million bpd nameplate capacity. However, the headline 7 million bpd figure overstates the amount that actually reaches the export market. Consider that approximately 1.5 million bpd of the 7 million bpd had already been flowing to feed two refineries that serve domestic Saudi consumption. Another 500,000 bpd of capacity is dedicated to LPG, a product stream with more limited uses as a refinery feedstock than crude oil. This implies a ceiling of incremental crude oil supply from the East-West pipeline of not 7 million bpd, but 5 million bpd. And the figure falls even further upon closer inspection. The East-West pipeline feeds the Yanbu Port on the Red Sea, where nominal loading capacity is 4.5 million bpd but tested capacity is closer to 4 million bpd. In wartime, throughput falls due to loading constraints. During wartime, Very Large Crude Carrier (VLCC) tankers loading crude at the Yanbu Port are required to sail during the day to avoid the hazards of nighttime travel and attacks by the Houthis. This travel constraint limits the number of vessels that can load crude at a given time, reducing export capacity from 4 million bpd to 3 to 3.5 million bpd. As a result, the headline of 7 million bpd of Saudi exports falls by half to 3.5 million bpd. Saudi Arabia is therefore capable of offsetting roughly 29% of the 12 million bpd of supply outages.

Iraq, the second-largest exporter through the Strait of Hormuz, has been devastated. Basra oil output has fallen by 76% to just 800,000 bpd from a pre-crisis level of 3.3 million bpd in exports. More production cuts are expected over the coming days if the Strait remains closed to Iraqi exports. The country declared force majeure on all foreign-operated fields on March 20 and is working to revive the Kirkuk-Ceyhan pipeline to Turkey, but the volumes are insignificant in the context of total Iraqi production losses. The pipeline is currently flowing approximately 250,000 bpd and will presumably reach full capacity of 500,000 bpd, at which point it will add 250,000 bpd of additional production, equivalent to 7% of Iraq’s total supply outages. Years of disrepair and underinvestment suggest the pipeline isn’t likely to achieve its 1.6 million bpd design capacity for several years. Certain Iraqi fields face the additional challenge that extended shutdowns increase the risk of geological and well damage. And to top it off, Iraq derives 90% of its government’s revenue from oil, so it faces a financial crisis on top of an energy crisis that will likely compound the supply disruption.

Kuwait is the most vulnerable Gulf producer. It has no bypass pipelines whatsoever. Every barrel of Kuwait’s 2.6 million bpd of production must transit Hormuz. The country has reportedly cut its production from 2.6 million bpd to just 500,000 bpd. The CEO of Kuwait Petroleum Corp. recently stated that it will take 3 to 4 months to fully restore the bulk of Kuwait’s production.

The UAE has the only other bypass pipeline outside Saudi Arabia. However, its ADCOP line from Habshan to Fujairah has only 440,000 bpd of spare capacity, a rounding error against the ongoing 12 million bpd supply deficit. Physical infrastructure damage at Fujairah and the Ruwais refinery, which was shut after a drone strike on March 10, further constrains even this limited workaround.

Altogether, Saudi Arabia, Kuwait, and the UAE have alternative pipeline capacity amounting to roughly 4 million bpd, representing one-third of the 12 million bpd of total supply outage. The remaining 8 million bpd must be sourced from Atlantic basin alternatives with 20-to-40-day sailing times. That represents roughly two-thirds of the total disruption with no near-term fix.

Recall that oil prices surged past $140 per barrel after Russia invaded Ukraine. At the time, the oil market expected the loss of 3 million bpd, which never actually materialized. Today, the market has been running an 8 million unresolved supply deficit for weeks. I find it amazing that Brent sits only slightly above $100 per barrel.

The SPR Is a Bandage, Not a Fix

Each successive SPR headline has had less market impact, and the math explains why. The entire coordinated global release of 400 million barrels across 32 nations amounts to roughly 4 days of global oil consumption. The U.S. contribution of 172 million barrels over 120 days implies a flow rate of 1.43 million bpd, covering just 12% of the approximately 12 million bpd that has been shut in. The U.S. SPR was at 415 million barrels before the release, roughly 58% to 60% of its 714-million-barrel capacity and not far above the 347-million-barrel historical low reached in 2023.

Note that by the fifth SPR announcement, oil prices didn’t react and then moved higher. The market has learned to discount SPR headlines because the volumes don’t move the needle against a disruption of this magnitude.

Crack Spreads Point to Physical Market Tightness

The refined product picture is also characterized by severe supply outages. The recent surge in crack spreads—the difference between the price of a refined product and the price of the crude used to produce it—puts them in reach of highs last seen after Russia invaded Ukraine.

Source: RBN Energy, March 26, 2026.

The gasoline crack is approximately $28 per barrel. The diesel crack has widened to $0.84 per gallon, 61% above 2024 levels. Jet fuel in Singapore has hit $227 per barrel. These margins provide refineries with a strong incentive to buy crude and run it. They imply that refining can remain profitable up to roughly $130 per barrel Brent. As long as that’s the case, crude demand from the refining sector stays firm even at elevated prices, which puts a floor under the physical market.

Refined Products: The Amplifier

The crude oil deficit is being compounded by a refined product squeeze that many investors fail to appreciate. On March 4, China banned all exports of gasoline, diesel, and aviation fuel via an order from the NDRC. Most of the world’s spare refining capacity resides in China. Its more than 19 million bpd of capacity versus its approximately 15 million bpd of refinery throughput, giving it significant excess production capacity and making its role in refined products analogous to Saudi Arabia’s role as the largest source of crude oil spare production capacity. By banning exports, China removed the single largest buffer for Asia-Pacific refined product supply. This has arguably been the most consequential policy decision of the crisis after the closure of the Strait itself.

After China’s move, South Korea has capped fuel exports, mandating that 90% of prior-year domestic volumes must be maintained before any exports are permitted.

Now, Australia is the canary in the coal mine. The days of remaining fuel supply have collapsed from 30 to 38 days before the crisis, to the point that more than 600 gas stations have run dry on at least one fuel type. In March, Australia imported 240,000 metric tons of U.S. fuel, the most in more than 30 years.

The situation is growing more acute elsewhere in Asia. Jet fuel in Singapore has surged to $227 per barrel from a pre-war baseline of $80 to $90 per barrel, while naphtha prices have jumped approximately 50% over the past month. VietJet has cancelled large-scale international routes, Air India has imposed surcharges, the Philippines has declared a state of national energy emergency, and Myanmar has imposed alternating driving days. These are not speculative outcomes. They are happening now.

The hoarding dynamic represents the tail risk that could push prices much higher. If more countries follow China and South Korea in restricting exports, or if the U.S. imposes any form of export restriction ahead of driving season, a 1970s-style panic-buying dynamic may take hold.

Timing Works Against a Quick Resolution

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In this piece, I will break down for you the various scenarios on the horizon. Now that we are nearly 4 weeks into this Iran conflict, what does that do to the oil market?

On March 9, we published a public piece titled, “My Latest Thoughts On The Oil And Natural Gas Market Amidst The Iran Conflict.” In it, I said:

Here’s what this means for oil prices (bbls lost scenario includes time to bring back production):

• Scenario 1: Tanker flows resume tomorrow: Brent will average in the high $70s to low $80s for the rest of the year. (~210 million bbls lost)

• Scenario 2: Tanker flows resume by March 15: Brent will average in the mid to high $80s for the rest of the year. (~290 million bbls lost)

• Scenario 3: Tanker flows resume by March 22: Brent will average in the low $90s for the rest of the year. (~370 million bbls lost)

• Scenario 4: Tanker flows resume by March 29: Brent will average in the mid-to-high $90s for the rest of the year. (~450 million bbls lost)

I don’t even want to contemplate what will happen to the oil market if tanker flows don’t resume to normal by March 29. Oil demand destruction is the only way out of it, and the prices will have to be extreme.

Soon after the report, IEA announced a global SPR release totalling 400 million bbls. This will dampen the impact of the supplies lost, but as we discussed in our follow up piece titled, “The IEA Just Gave Oil Bulls The Biggest Gift Ever By Coordinating The SPR Release.“ I wrote:

From an oil trading standpoint, traders will be reluctant to push oil prices up until the cushion is gone. The simultaneous SPR release will help dampen a lot of the worries over immediate supply needs, but it will only be a short-term fix. The market will remain on edge and with each passing day that tanker flows don’t return to normal, oil prices will gradually shift higher.

On the downside, an immediate ceasefire or any truce will send oil spiraling lower. For example, if a peace deal is announced before March 15, the net balance to global oil inventories will be +110 million bbls (400 million bbls - 290 million bbls).

This has the potential to send Brent back into the mid-$70s.

On the other hand, if there is no peace deal, and the disruption lasts until the end of March, the net balance will be -50 million bbls. With each passing week, the deficit increases by ~80 million bbls.

So yes, SPR buys time, but it does not fix the issue at hand. Tanker flows need to return to normal.

Thankfully, it does prevent a catastrophic price spike scenario in the near term, which will prevent meaningful demand destruction from taking place.

Fast forwarding to today, we are now at the March 29 scenario we laid out at the beginning of the month. Let’s look at the latest facts to discern where the oil market is headed.

Facts

Production shut-in total from Saudi Arabia, the UAE, Kuwait, Iraq, and Bahrain has reached 10.98 million b/d.

• Iraq: -3.6 million b/d

• Kuwait: -2.35 million b/d

• UAE: -1.8 million b/d

• Saudi: -3.05 million b/d

• Bahrain: -0.18 million b/d

Saudi has maxed out the East-to-West pipeline. It is currently exporting ~4 million b/d in the Red Sea.

The UAE can also bypass via the Abu Dhabi pipeline (Habshan-Fujairah). The ~1.8 million b/d is also maxed out.

Tanker traffic flow in the Strait of Hormuz remains nonexistent. The fact is that even if the war ends tomorrow, it will take a few months to increase production and resume normal traffic.

Scenarios

I will give you three scenarios:

• The war will end by the end of this week. Traffic returns this weekend.

• The war ends by the middle of April.

• The war ends by the end of April.

Keep in mind that the SPR release of 400 million bbls bought the oil market more time versus our initial assessment (from March 9). Oil price scenarios below will reflect the change in SPR.

Scenario 1: Ends this week

Impact on global oil inventories: -50 million bbls (including SPR release)

Impact on Brent: initial sell-off into the low-$80s before averaging in the mid-to-high $80s for the rest of the year.

Scenario 2: Ends the middle of April

Impact on global oil inventories: -210 million bbls

Impact on Brent: initial sell-off into the low-$90s before averaging in the mid-to-high $90s for the rest of the year.

Scenario 3: Ends at the end of April

Impact on global oil inventories: -370 million bbls

Impact on Brent: initial sell-off into the $110s before averaging $110-$120 range for the rest of the year.

Breaking Point: Mid-April

For the oil market, there will be a breaking point. For the time being, the market is taking the view that the conflict will resolve before the middle of April. This view is important in the context of analyzing where oil prices are headed.

Oil is priced on the margin, and as long as there’s enough “supply” to go around, the market won’t panic. What you are seeing in the oil market today is a lack of panic. The combination of jawboning from the Trump administration, sanction relief on Iran/Russian crude, and the SPR release have kept prices at bay. None of it will work once we hit this breaking point.

For now, the evaporation of global oil-in-transit has not translated to onshore inventories just yet. Our estimate is that by the middle of April, this will come full steam ahead.

If the conflict is not resolved by mid-April, IEA will need to coordinate another SPR release of ~400 million bbls. Without this action, oil prices will reach demand destruction levels ($200+).

Longer-Term Impact

In Energy Aspect’s latest weekly perspective, it noted that the total supplies lost for the market will total ~930 million bbls. It is estimated that the cumulative production lost from May to December is ~340 million bbls.

Their estimate is far more aggressive than ours. In our storage sensitivity analysis, we did not factor in how countries like Iraq and Kuwait will take 3-4 months to bring production back to normal. It appears that we may be far too conservative on this front.

For Goldman, the longer the conflict lasts, the higher oil prices will last.

In the above scenario, Goldman gives the scenarios of what it would look like if the conflict is prolonged for another 10 weeks. It aligns with the scenario we gave above.

In essence, there’s a breaking point in the oil market. Once we’ve crossed the rubicon, there’s no going back.

Readers should expect structurally higher oil prices going forward. The supply losses we are seeing today will have a meaningful impact on global oil balances going forward even if the war ends at the end of this week.

How Long?

I have so far refrained from commenting on “when” I think this conflict will end. This is motivated in part from not jinxing myself and in part because I have no idea when it will end.

But I will just say this, unlike the previous conflicts, where there were efforts made to “escalate to de-escalate”. I just don’t see any of that now. The retailiatory attacks are done with zero notice. Iran appears to be targeting Gulf nations as opposed to just targeting Israel alone. The response is what initially prompted me to think that, “this time was different.”

Now that the conflict has gone on for nearly 4 weeks, I fear that with each passing day there’s no deal, the probability of a deal diminishes greatly. As I explained in our piece titled, “Running Out Of Time.” Iran is fully aware of the math behind the oil market. All it needs to do is wait for the breaking point to unfold in the oil market before extracting max concessions from the US. From a tactical standpoint, it has no advantage to reach a deal now. The Strait of Hormuz card has been played and it can’t be replayed again in the future.

For the Gulf Coast countries, if the current Iranian regime is not toppled, it will be held hostage to this situation time and time again in the future. This is unacceptable even if there’s some framework for a “toll fee” going forward.

As a result, the logic leads me to believe that it’s not up to the US to dictate terms here. It’s up to the Iranians, and given this being the case, it will push for the breaking point in the oil market. It will test the US’s resolve. All it needs to do is “survive” for another 3 weeks before things start to break.

But again, I am not a geopolitical expert. I have no idea what I’m talking about here. All I can tell you is that from a fundamental standpoint, this is where we stand today.

Analyst’s Disclosure: I/we have a beneficial long position in the shares of USO, UCO either through stock ownership, options, or other derivatives.

I am long: USO May 15, 2026, $215-$245 call spread, USO May 15, 2026, $135 call.

Without a doubt, the war in Iran is impacting the titanium dioxide market. Notwithstanding today’s news regarding prospects for U.S.-Iran talks, a prolonged war and/or outage in the Strait of Hormuz is still very much on the table. The situation begs the question of how an investor in titanium dioxide stocks should be positioned if the war continues for weeks or months.

As subscribers know, I have been long the titanium dioxide producers Chemours (CC), Tronox (TROX), and Kronos Worldwide (KRO) since late last year, when their stocks were significantly lower than today. I published my recovery thesis in an article published in November. The article made the case that a titanium dioxide recovery was imminent, driven by 1.1 million tons of production curtailments, anti-dumping measures across the EU, Brazil, India, and the U.S., and market-share consolidation among the big three Western titanium dioxide producers.

That thesis remains intact, with evidence now being reported more widely. This is the main reason why the titanium dioxide producer stocks have held up well despite the broader market turmoil, which has hit economically sensitive names particularly hard. Supply and demand are more closely balanced than they have been in years, allowing prices to inch upward. Tronox guided to sequential pricing gains of 2% to 4% in the first quarter of 2026, and Chemours confirmed that its December price increase took hold in the market, with buyers accepting the higher price rather than pushing back or switching suppliers.

So far, all signs suggest that price increases are holding, indicating that the market is in the early stages of a recovery. However, because the recovery is still in its early phase, it remains vulnerable to negative macroeconomic forces. A demand shock from the war in Iran and/or a prolonged outage in the Strait of Hormuz could cause such a setback, which raises the risk for investors in titanium dioxide stocks.

The Sulfur Shock Hits Sulfate Producers Hardest

The war’s most direct impact on titanium dioxide comes through sulfur. Sulfur is a byproduct of oil refining and natural gas processing. The Gulf states account for roughly 45% of global supply. The near-total halt of tanker traffic through the Strait has severely disrupted that supply, sending U.S. sulfur prices up by more than 150% year-over-year to around $500 per metric ton. Prices in Asia have surged by a similar magnitude.

This matters because the sulfate manufacturing process requires approximately 4.0 to 4.5 metric tons of concentrated sulfuric acid per ton of ilmenite concentrate. Approximately 80% of China’s titanium dioxide output uses the sulfate route, and China produces more than 60% the world’s titanium dioxide. The sulfur crisis, therefore, imposes a direct and significant cost shock on roughly half of global titanium dioxide capacity.

The Western majors, namely Chemours, Tronox, and Kronos, use the chloride process, which does not rely on sulfuric acid. As such, they are largely insulated from higher sulfur and sulfuric acid prices. This widens the cost gap between Chinese sulfate producers and Western chloride producers at a time when anti-dumping tariffs of 14% to more than 40% are already squeezing Chinese export volumes.

North America’s Demand is Advantaged

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