There’s a scene from Top Gun where Tom Cruise goes head-to-head against Viper. Goose says, “Holy shit, we are going head-to-head. I can’t believe we are doing this.”

This was what PauloMacro said to me when I described to him the incoming US crude inventory draws I was compiling.

Yes, I guess we are really doing this.

As I sit here compiling the tanker flow data I’m seeing in the US Gulf, the thing that should be duly noted is the following:

• We are still offloading some of the tankers inbound laden with crude. These are temporarily keeping US crude imports elevated. The same VLCCs discharging crude turn into export volumes in 1-2 weeks.

• We have an armada of empty VLCCs headed for the US, which will drain US commercial crude inventories dry.

• All the while, we will continue to drain product inventories in the US. Petroleum product exports are expected to remain near all-time highs.

The snapshot above is our preliminary US crude storage estimate for next week, which includes 7.1 million bbls from the SPR. The final SPR release figure could be higher next Monday, so we will have finalized estimates out by then.

What’s not shown above is what happens to US commercial crude storage when 1) US refinery throughput ramps up to 16.8 to 17 million b/d and 2) US crude imports fall to 5.5 million b/d due to lower inbound crude flows.

As I was explaining to Paulo, the net impact on US commercial crude inventories by the middle of May is as high as 12 million bbls.

Yes, 12 million bbls.

In essence, there could be EIA oil storage reports showing -10 to -12 million bbls of crude WITH a SPR release of 10 million bbls. This would put the cumulative crude draw at 20 to 22 million bbls.

And since I’m a numbers guy, let’s just say this. Since EIA started publishing the weekly oil data in 1982, there have been 41 weekly crude draws of over 10 million bbls. The largest ever recorded crude draw (commercial + SPR) was on the week of July 28, 2023, and this week’s EIA oil storage report (-13.355 million bbls) already ranks as the 6th largest crude draw in history.

So yes, we are on pace to break records. I wasn’t kidding when I said Big Ass Crude Draws are coming. BACD is coming, and I don’t think the market is even aware of this. (The estimate for next week’s report ranks as the 8th largest crude inventory draw in history.)

Note: I think physical oil traders are very aware of this. But the algo trading funds that buy and sell oil based on the EIA data? No, not at all.

Here we are...

I guess we are really doing this. We are really going to just watch the Strait of Hormuz stay closed, and onshore oil inventories plummet. US product storage is already approaching seasonal lows for this time of year, and the next few weeks will push us into brand-new territory.

I still see commentary about comparisons to 2022. The absurdity of those comments fails to recognize that this is not even remotely similar.

But here we are nonetheless. The endless comparisons to historical analogs that have no relevance to anything we are seeing today. It is what it is. It would take me days to write and debunk all of the bad information out there, or I can just wait and let the market slap some sense into them. I think I will choose the latter and just position myself accordingly. When the market gives you a gift, you take it and give thanks (as Shrub always says).

So yeah... I really can’t believe we are doing this.

The draws are coming.

It is what it is.

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

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.

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.

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.

How much does this change the oil market?

Nothing.

Zero.

No change, whatsoever.

Every oil trader that doesn’t live under a rock knows this.

Iran has been exporting freely since the Biden administration turned a blind eye to Iranian crude exports in 2022.

The chart above, based on Kpler data, does not include all shadow-fleet volumes. IEA estimated that Iran’s production is near 3.55 million b/d, or just 250k b/d below the 2018 highs.

Source: IEA

By our estimate, Iran, including the shadow fleet, is exporting ~350k b/d more than the figures reported above. If so, Iran was exporting near max capacity prior to the conflict.

The temporary sanction lift allows others to buy the current oil-in-transit. The issue here is that the OFAC license still restricts the flow of money to Iran, so China remains the only logical buyer.

Following Trump’s sanctions in 2018, Iran adapted. After the crude is loaded at Kharg Island, various ship-to-ship transfers are conducted, with the final crude “originating” from Malaysia.

This chart from Giovani Staunovo is a great illustration of this:

P.S. Malaysia produces around ~570k b/d, most of it for internal use. It is physically impossible to export that volume to China.

Now that you know the general mechanics of this, you will quickly realize that the US sanctions lift just reduces the friction between the seller and the buyer. Malaysia won’t play a role in oil-in-transit anymore, and since the oil flow was already underway before the sanctions were imposed, the impact on the oil market is nil.

Analyst’s Disclosure: I/we have no stock, option or similar derivative position in any of the companies mentioned, and no plans to initiate any such positions within the next 72 hours.

To put into context the magnitude of an export ban, here are the figures you should know:

• US crude exports average ~4 million b/d, or ~9% of global seaborne crude exports. Europe gets ~1.8 million b/d of crude, and Asia gets ~1.6 million b/d.

• If the US bans petroleum exports, it will increase the current “flow” outage we are seeing out of the Strait of Hormuz. The US exported ~10.7 million b/d of petroleum products in 2025, effectively doubling the current outage. Strait of Hormuz flow outage is ~11 million b/d, and the US petroleum product export ban would be 10.7 million b/d, bringing the total outage to 21.7 million b/d. In the context of global oil market fundamentals, this is ~20% of global oil demand.

• US crude oil production is ~13.5 million b/d with plant condensate accounting for an additional 0.7 million b/d. Refineries in the US are not geared to process ultra-light sweet crude produced by US shale producers. The EIA stopped producing the crude quality table that illustrated the different grades, but based on a rough estimate, the US produced close to 7 million b/d of API gravity 40+ crude. US refineries run an average API gravity of 33. This quality mismatch will reduce US refinery throughput.

Would a crude export ban lower oil prices in the US?

Yes.

Would a ban on petroleum product exports lower prices in the US?

Yes.

But... and this is a really big issue, US shale oil producers will suffer greatly. At the moment, Brent-WTI spreads are blowing out, with WTI remaining flat, but the scenario I’m going to explain will show why WTI will go down.

Every week, we publish our US crude storage estimate. We have built this expertise over the last 8 years. Yes, it’s a long ass time to be doing something like forecasting US crude storage.

In the above scenario, a hypothetical roadmap of what would happen to US commercial crude storage on a weekly basis if US crude exports were banned.

If product exports were also banned, it would further lower US refinery throughput, but for this mental exercise, we will only look at crude.

At the moment, US commercial crude storage is at 449 million bbls. In 2020, US commercial crude storage topped out at around ~540 million bbls. This coincided with Cushing reaching the tank top level of ~65 million bbls. The operational maximum capacity is between 540 to 570 million bbls.

By our estimate, if US crude exports were banned and US shale producers continued to produce the exact same volume, US commercial crude storage would hit tank top by mid-April.

Please keep in mind that the market will likely force a response before that by sending WTI sharply lower, forcing producers to shut in production.

The US commercial storage landscape and the shale boom were built on the notion that we can freely export crude and products. Without the export ban being lifted in 2015, US shale producers would never have had the room to grow production meaningfully. It was thanks to the lifting of the export ban that this happened.

Now, if we assume that US refineries continue to draw down medium/heavy crude during this time period, and we start to price out seaborne crude imports, this is what the weekly balance would look like:

At +15 million bbls per week, we will reach tank top by the first week of May.

Again, if this scenario happens, storage in PADD 3 would swell, basin crude differentials would blow out, and US shale producers would have to shut in production.

This is not a scenario you even want to contemplate here. It’s like shooting yourself in the foot.

Investment Implications

If the Trump administration bans US crude exports:

• Short WTI

• Long Henry Hub

• Long natural gas producers in the US and Canada (associated gas production will fall due to production shut-in)

• Be ready to buy the dip in US and Canadian oil producers.

Because of the implications I wrote above, the export ban, if enacted, won’t last long at all. Storage tank tops will force the Trump administration to act, so we don’t see this lasting more than a month.

Readers who are aware of the dynamics can take full advantage of this disconnect.

Analyst’s Disclosure: I/we have no stock, option or similar derivative position in any of the companies mentioned, and no plans to initiate any such positions within the next 72 hours.

Background

Many of you are familiar with the origin of the COVID virus, so I will not bore you with that. Instead, let me help you understand the oil market setup going into 2020.

At the start of Q4 2018, President Trump was set to announce sanctions on Iranian oil exports. By the end of September 2018, OPEC+’s Joint Ministerial Monitoring Committee (JMMC) met and said that there’s nothing more they can do to prevent Brent from surpassing $80. In particular, Saudi’s energy minister (at the time), Khalid Al-Falih, said:

Asked if prices were too high, he replied, “I cannot speak to prices because I do not directly influence prices. What I can directly influence is ensuring that markets are well supplied, and that we will do today.”

Two weeks later?

President Trump pulled his first “TACO” by announcing an exemption on the oil sanctions. Oil prices went into a freefall.

OPEC+ met in December 2018 and decided that it was time to reduce output again. After increasing output at the end of June 2018 at the request of President Trump, OPEC+ reversed course.

Throughout 2019, Brent traded in a tight range between $59 to $73.

The physical oil market was tightening with refining margins staying elevated. The market consensus was that the global oil demand outlook was uncertain due to the US/China trade war. Most analysts expected 2020 oil market balances to remain constructive, and US shale producers had just adopted the religion of spending within cash flow (after the 2018 spending spree).

Coming into early 2020, oil market fundamentals were healthy. Inventory changes were slightly better than the seasonal norm. But by the end of January, the news of a mysterious virus was making headlines in mainstream media. Some very smart oil traders (we were not one of them) saw the Chinese government’s response (lockdown) and extrapolated it to the rest of the world. Pierre Andurand was one of them, and his fund made a killing shorting oil during the lockdown and bought the dip on the way up.

By early March, it was evident that OPEC+ had to meaningfully cut oil production to prevent the world from hitting storage tank tops. Global oil demand, at the time, was assumed to have fallen by at least ~3 to ~4 million b/d. OPEC+ had to cut production by at least that much. But in-fighting amongst the Russians and Saudis prevented a large production cut from taking place.

For some of us who have been in this sector for a long time, March 8, 2020, was one of the worst days in living memory. Saudis, in the middle of the pandemic lockdown, announced the most aggressive oil price war in history. Instead of cutting oil production by ~3 to ~4 million b/d, the Saudis turned on the taps and increased production to their maximum capacity. In addition, the Saudis announced record cuts to official selling prices in every region of the world. Europe saw the largest price cuts, as this hurts Russia the most.

Immediately after the announcement, oil prices went into a freefall.

During that time period, people fretted over the possibility that this oil price war would kill oil producers forever. The one part of the analysis that most analysts did not write about at the time was how realistic the duration was. We took a look at the economics and concluded that there was no way this would continue.

In addition, the Russians could not afford to produce at that price. Production shut-in was inevitable, and if that was the base case, agreeing to a product cut is the most obvious course.

Fast-forwarding 3 weeks later, on April 9, 2020, OPEC+ agreed to the largest production cut in history: 10 million b/d.

Funny side note: Mexico, a non-OPEC member, almost blew the deal apart because it did not want to cut oil production. It was going to show declining oil production even if Brent went to $80! I remember the frustration I felt at the time, reading the headlines coming out of the OPEC+ meeting. The good old days.

Was the oil market saved?

No, and this is where the history lesson is helpful in understanding the oil market today.

Relevance to the Oil Market Today

OPEC+’s production cut didn’t take effect until May 2020. The low oil prices at the time had already forced most OPEC+ producers to cut production. Saudis were the only exception at the time as total oil exports exceeded 10.5 million b/d!

The mismatch between elevated production and the demand drop from COVID-mandated lockdowns left the oil market in a temporary surplus of ~20 million b/d. And since the Saudis don’t start cutting oil production until May, April was going to be a brutal month.

Sell-side analysts started estimating how quickly the world would hit tanktop in oil storage. Will the super contango we see in the oil curve push floating storage on tankers to an all-time high? Will VLCC rates 5x?

The narrative started to gain momentum. Couple that with real-time data showing a massive jump in oil inventory, and the world started pricing near-term oil futures as if tanktop were a reality. We all know what happened next: oil prices went negative.

Source: CNBC

What is the relevance to the oil market today?

Strait of Hormuz tanker flow remains low. Yes, we are seeing tankers go through with AIS turned off, but the flows remain a fraction of what they were before the conflict started.

Despite the whipsaw in the oil market today, history tells us this is not the end of the price move. Amid COVID, OPEC+’s historic intervention was unable to prevent a further collapse in oil prices.

This time is the reverse.

With each passing day that goes by without tanker flows returning to normal, Gulf Coast Countries (Iraq, UAE, Kuwait, Qatar, Saudi) will see onshore inventories build. Once storage reaches capacity, production will be shut in. (Note: This is already happening with Argus estimating production shut-in between 6.2-6.9 million b/d.)

Simultaneously, global oil inventories will begin to decline by ~11 million b/d. We are currently absorbing the excess we have on water, but once that’s gone, visible oil inventories will show a rapid decline.

Similarly, even if tanker flows return to normal by tomorrow, the production shut-in situation will take weeks to return to normal. Every day that goes by, the situation worsens.

So was $119 the peak?

I don’t know. But if history is any guide, we will reach an obvious extreme before this ends. Don’t rule out another price spike in the making. Remember, the oil market only had 2 weeks of cushion. If tanker flows don’t return to normal by the end of this week, I fear the worst has yet to come.

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

Unprecedented, that’s the only way to describe everything that’s going on in the energy market today.

The Iran conflict is creating the largest supply reduction in the history of the oil market. No other disruption even comes remotely close to this.

We have been updating in real-time the tanker flow videos on X, and things look grim.

Some tanker tracking firms have noted that tankers are still moving through the Strait of Hormuz, but their AIS (automatic identification system) is turned off.

That’s probably the case, but the most important point still stands: the traffic in the Strait of Hormuz is nonexistent.

With each passing day that goes by with no visible tanker movement, these are the impacts on the energy market:

• ~19 million b/d of crude, condensate, and products.

• ~20% of global LNG.

Natural Gas (LNG Market)

At the moment, Qatar has reduced or shut down its LNG facility, which would take weeks to come back online. This is ~20% of global LNG flow, and with each passing day, the global natural gas storage situation worsens.

The situation in the global natural gas market is unique because natural gas is a unique commodity. Natural gas is a time-sensitive commodity. We should all be thankful that we were past the heart of the heating demand season before this chaos unfolded, but as the injection season gets underway, we have 32 weeks (from the beginning of April to November) before we enter the next heating demand season.

These injection months are crucial to price stability in the upcoming winter. Without sufficient natural gas storage, we will have uncontrollable price spikes. In 2022, Russia invaded Ukraine in March, after the heart of the heating demand season, European natural gas prices reached levels that destroyed industries.

We are on a similar path.

Source: Giovanni Staunovo

Luckily, this time around, US LNG exports are meaningfully higher than in 2022 (+8 Bcf/d), so the price spike won’t be as severe. (Note: The US supplies ~36% of global LNG flow.)

But as long as Qatar’s outage persists, US natural gas prices will continue to rise. US LNG exports this year will operate at max capacity. We alluded to this effect when we discussed our long BOIL position in this write-up.

By the end of this week, if the Strait of Hormuz situation doesn’t correct, Henry Hub will reach $4.5/MMBtu+. Some of you might be wondering, shouldn’t Henry Hub trade according to US natural gas fundamentals? Yes, but a similar thing unfolded in 2022 when global natural gas prices skyrocketed. We don’t expect a similar parabolic rise this time around, but it’s not correctly priced at $3.42/MMBtu (prompt month).

Oil

This is what the Strait of Hormuz closure (not technically closed) is doing to the oil market.

• Each day that goes by with no flow, oil-on-water is dropping by ~11 million bbls (~77 million bbls per week).

• Production shut-in has already reached ~4 million b/d, and by the end of this week, this figure is expected to hit 6.5 to 7 million b/d. Storage capacity is reaching its limits in Iraq and Kuwait. The UAE is next, followed by the Saudis. Saudi oil production won’t shut in unless this conflict lasts more than a month, but the damage to the global economy would already be done.

• Even if the tanker flows return to normal tomorrow, logistical jams will keep production shut-in for at least a month.

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.

As for the prompt-month oil futures, each passing day will result in more severe, more parabolic moves. My guess will be as good as yours, and so my advice would be to use the scenarios above to figure out what price you want to pay for energy stocks using our updated E&P valuation sheet.

What is the catalyst to fix this?

We initially thought that the Trump administration’s policies on DFC insurance (for tankers) would at least encourage some tankers to move. That’s clearly not the case.

Jon and I have debated about how this will be resolved. Jon’s view is that Trump will give up on this because of the following reasons:

• Trump will TACO because of elevated oil prices, the impact on the global economy, and the timing for the midterm elections.

• High oil prices will hurt the US economy, his voter base, and the outcome of this year’s elections.

• The disruption is too great for it to continue.

It’s hard to argue against all that.

Now, what happens if Trump doesn’t TACO?

• Naval escort + ground invasion in the South to secure the Strait of Hormuz stretch. This would take a long time.

• A far bigger and better insurance coverage is provided by the US. Dr. Anas Alhajji continues to believe that it’s an insurance issue preventing the tanker flows from resuming. If so, the DFC will have to substantially increase the coverage size of $20 billion.

• Iran reaches a peace agreement with the US and Israel. That seems unlikely given everything that has unfolded so far. Mojtaba Khamenei is now the Supreme Leader, and he appears to be more hardline than his father was.

In essence, outside of a full retreat, the conflict will continue, and given the uncertainty on tanker flow, things look grim for now.

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

US shale is not coming to the rescue. Don’t even think about it.

Yes, producers are hedging like crazy. Can you blame them? After going through a decade-plus oil bear market and oil prices are finally moving up, you think they will just sit there and let you rug pull that away from them?

Hell no. And what’s really funny about all of this is that none of these producers will increase capex.

Oil price spiking? Thank you for the extra free cash flow. I’m going to save it for a rainy day.

In the best case scenario, oil producers will be looking at these price spikes to think about spending more money on enhanced oil recovery. It’s not for drilling. No one is going to increase capex because of a geopolitical event. That’s crazy talk.

Imagine having an executive team present a revised capex budget to the board and the justification is:

We are at war with Iran so we need to do our part in supplying the world.

Where the hell was the patriotism when Trump’s team was talking about $50/bbl oil after the Venezuela event?

So again, no, US shale is not coming to the rescue. Throw that idea out of your head.

Fundamental Mismatch

US shale oil production has already matured. The growth phase is behind it.

At HFIR, we track US crude oil production on a real-time basis. And as you can see in the chart above, EIA has been lagging our production estimate since 2022. It wasn’t until late last year that EIA is now firmly above our estimate, which implies that US crude oil production is overstated.

The fact that US crude oil production hasn’t meaningfully broken above ~14 million b/d is a sign that it’s the ceiling.

Using our latest updated forecast for US crude oil production, if WTI holds at $70/bbl, we could see a scenario where US crude oil production rises to ~14 million b/d. If WTI averages $80/bbl, we could see ~14.5 million b/d, but that’s the absolute peak.

That represents growth of ~350k b/d to ~850k b/d from Dec 2025 volumes. That’s not a lot of growth left.

Knowing this fact, you can expect the energy executives looking at the oil price spike and thinking, how can we maximize our inventory today.

Does that entail drilling everything now? Hell no.

You keep your overall production decline profile low, slowly drill your best inventories, and continue to de-risk the reservoir. You don’t cowboy your way into an oil price spike thinking it will last forever; you have a business to run and board members to answer to.

So again, US shale is not coming to the rescue. It’s just not happening.

Analyst’s Disclosure: I/we have no stock, option or similar derivative position in any of the companies mentioned, and no plans to initiate any such positions within the next 72 hours.

The US and Israel launched a joint attack on Iran this weekend. The key highlights are below:

• Iran’s Supreme Leader Ayatollah Ali Khamenei was killed.

• Multiple top leadership positions in the Iranian regime have also been eliminated. President Trump noted that “Operation Epic Fury” was so successful that the replacement candidates were also killed.

• Iran responded by attacking Israel, US bases, and Gulf Nations, including Qatar, the UAE, Kuwait, Bahrain, Jordan, Saudi Arabia, Iraq, and Oman.

• Marine insurers began cancelling existing war risk policies for vessels in the Gulf and Strait of Hormuz over the weekend. In Kpler’s blog post update, it noted that while the Strait of Hormuz isn’t technically closed, the lack of insurance has slowed tanker traffic. This has major implications for global commodity flows:

Source: Kpler, Matt Smith

Only Answering The Questions We Know The Answers To

Updated on March 2nd, below is my gameplan:

I’m not a geopolitical expert, and I won’t pretend to be one. The reality is that many of us have no idea what to expect between the US, Israel, and Iran. We can only answer the questions we know the answer to, so instead, I will write the following section in an interview format.

How long will the US, Israel, Iran conflict last?

I have no idea.

How does this impact global energy trade flow?

If we don’t know how long this conflict will last, we have no way of knowing the impact on the trade flow. One can use an estimate for the duration of the conflict, but this framework will not provide any value because it’s just pure speculation.

Where should oil trade without geopolitical conflicts?

$59-$62

By H2 2026, we see WTI trading in the $65 to $70/bbl range.

Geopolitical risk premium today (with WTI at $70 is about $8 to $11/bbl).

From your experience, does the current conflict match the ones you’ve seen in the past?

Over the weekend, I wrote a post on X as follows:

My gut hunch is that this time feels different. Iran’s Supreme Leader just died. The remaining Iranian leadership has already seen what it looks like to be negotiating with the Trump administration. Sources on the ground from the previous week were indicating that a peace deal was close, only to have Israel and the US take out the leaders over the weekend. Even from a diplomatic standpoint, it seems hard to justify further negotiations. But that’s just my gut hunch, and I have no facts to back this.

How would you trade your current long oil position?

I’m paying attention to the physical oil market moves more than anything else. Historically, the peak has always coincided with some dramatic move happening in the spreads. As you can see, the Brent 1-2 timespread is spiking, which is perfectly sensible. Meanwhile, the Brent-WTI spread is also spiking, indicating that traders are trying to pull the barrels out of the US.

Brent 1-2

Brent-WTI

I’m long USO with a cost basis of $73.56. I think the risk/reward for a long position becomes unfavorable if WTI reaches $75/bbl. We are not far from there with WTI trading at $71.50.

My gameplan is to monitor both the physical oil market and the geopolitical development. Again, there’s no way of knowing when the conflict will end. If WTI gets to $75/bbl, I will look to exit.

Would you short oil after closing your long position?

No. Because the geopolitical side is very hard to predict, it’s best to take no action.

What do you make of the OPEC+ production increase over the weekend?

OPEC+, excluding Saudi and the UAE are already producing near max as I wrote in this article.

I think the production increase is more symbolic than anything else. Saudi, on the other hand, is fully capable of increasing exports to fill any gaps left behind by Iran or others. If Brent continues to move higher, we should see Saudi crude exports jump.

What about China?

China’s crude buying will slow with oil prices where they are today. The excess build-up we saw throughout 2025 will be used to replace some of the demand this year. One of the key tailwinds for this year’s oil market balance was China’s SPR buying, so higher oil prices will reverse this tailwind into a headwind.

In addition, China will start importing more Russian crude following the disruptions we are seeing in the Strait of Hormuz. We could see a meaningful drop in oil-on-water as this gets absorbed onshore.

Again, higher oil prices will just slow China’s crude buying, which is in itself a headwind.

What about natural gas?

A lengthened conflict that disrupts shipping flow in the Strait of Hormuz will boost global LNG prices. This will, in turn, boost demand for US LNG exports, which will push Henry Hub prices higher. It won’t be a 1:1 impact, but the higher demand will be nice considering that the first half of March is expected to be one of the warmest since 2000.

Now, if the weather starts to moderate as I’m seeing now, I expect natural gas prices to recover back to $3.5/MMBtu. A big driver of US natural gas prices will still be dependent on the weather, so geopolitical conflicts or not, the market will remain fixated on fundamentals in the US.

Do you think energy stocks will move higher?

In general, when oil and natural gas prices rally, energy stocks follow. But since it’s geopolitically driven, energy stocks don’t usually follow it 1-to-1. The main reason is that no one buys energy stocks because of a temporary bump in price. We would have to see a sizable change in the futures curve before valuation multiples rerate. And at the moment, a lot of energy stocks are ahead of fundamentals, so it’s more likely we see them take a breather.

What’s the takeaway for readers?

No one knows how long the conflict will be. But just know the following:

• Iran is already producing at max capacity (~3.55 million b/d of crude). Any disruption is asymmetric to the downside for supplies.

• Fundamentally, WTI should be trading near $60/bbl, but we are already trading at $71.50. The risk/reward becomes unfavorable if WTI gets close to $75/bbl. That’s the level where we will take profit on our USO long.

• If we exit our oil long (not exiting energy stocks here, we are bullish long-term), we are not going to short oil. Geopolitical risks are too uncertain and too unpredictable.

• Prolonged conflict will be bullish for natural gas as global LNG prices move higher. Henry Hub pricing will still be predominantly influenced by US gas fundamentals, but higher LNG demand will be a small tailwind.

• OPEC+ supply increase for April is more symbolic than something material. Saudi has the spare capacity to meet any supply shortfall in the near-term (to an extent). If you really want to know what OPEC+ is doing, just watch Saudi oil exports.

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

By: Jon Costello

As a capital-cycle investor, the chemical sector piqued my interest in the second half of last year. We began investing in the space late last year.

Since then, chemical stocks have started to recover, with further gains likely if the recovery continues. What were potential three- or four-baggers a few months ago can still double or more from their current prices.

As we made our investments, I published a series of articles outlining my views on the sector, its cyclical properties, and my favorite investment prospects. This article provides a review of my macro and micro theses for the cyclical chemical sector.

Part I: The Chemical Sector: Olefins and the Rest

The chemical sector is in its longest downturn in recent history. For many chemical companies, earnings have been on a downward path since 2021. As demand remains tepid amid abundant supply, the industry faces several headwinds, both cyclical and structural. However, opportunities are there for investors who understand the risks and potential upside.

After reviewing the industry, I have found a few crucial points for investors navigating the sector in search of bargain opportunities.

One is that opportunities are absolutely there for the taking. Anyone who looks at the past earning power of the typical industrial or commodity chemical company and compares it to today’s market cap and enterprise value can appreciate that most of the sector is cheap. Many chemical stocks trade at obscenely low multiples of mid-cycle earnings. Interestingly, this isn’t the case in the energy sector, where most stocks discount a sustained recovery. But even using extremely conservative valuation assumptions, I believe multi-baggers exist in chemicals for investors who can identify opportunities, size their positions appropriately, buy on weakness, and stomach the inevitable volatility that arises in cyclical downturns.

A second crucial point is that cyclical forces will bring about a recovery. No one can precisely time when this will occur, though I believe a recovery is underway for some chemical sub-sectors.

For example, some particularly cyclical chemical sub-sectors are experiencing low prices that will likely lead to supply curtailments. Eventually, inventories will get worked down, prices will increase, and margins will grow. Meanwhile, in areas that may remain weaker for longer, low-cost producers are available. These are the companies that are most likely to survive the downturn and thrive in the ensuing upcycle. These are the kinds of opportunities investors should try to identify.

Such low prevailing prices raise the question of whether the sector’s low valuations are justified. This is another crucial point worth fleshing out, namely, that olefin producers are cheap for good reason. This is a large segment of the sector by market cap, and it often tops the buying lists of many generalist bargain hunters. Companies such as Dow (DOW), LyondellBasell (LYB), and Westlake (WLK) are at risk of a far more brutal downturn than their non-olefin peers. Their stocks are right to be low and will likely remain so, as their profits are at risk of moving even lower for years. Any recovery is likely to be fleeting.

This isn’t necessarily the case for non-olefin producers, though I suspect that many have been tarred too negatively with the olefin brush. Investors can therefore divide the chemical sector into olefins and “everything else.” The former are to be avoided altogether, and I discuss why below. The latter is where mispricings can be found.

The Factors Driving the Olefin Glut

Olefins are hydrocarbons that contain at least one carbon-to-carbon double bond. The main olefins are ethylene, propylene, and butenes. They’re made by steam-cracking ethane, propane, naphtha, and other hydrocarbons. Olefins serve as the building blocks for polyethylene, polypropylene, and various intermediaries. Polyethylene and polypropylene are the building blocks of plastics.

Investors in chemical companies should be aware that overinvestment has severely diminished the prospects for returns in the olefins market.

The culprit behind the oversupply is investment by the integrated oil majors to expand their downstream chemical operations. Their investments have been focused mainly on expanding production of ethylene, polyethylene, polypropylene, and aromatics. The onslaught of new supply threatens to lower the margins and returns on capital for olefin producers for years to come.

Since 2015, the annual production capacity of light olefins—ethylene and polyethylene—has increased by more than 50%, from approximately 230 million tons to 430 million tons. The growth outpaced real global GDP, which grew by roughly 25% over the same period.

Source: Oilchem, GlobalData, ICIS, and Wood Mackenzie.

The surge in investment came as the narrative about the future of gasoline and diesel demand turned negative. Virtually all the majors bought into the idea that demand for their biggest-selling refined products would peak and begin to decline in the 2030s. Oil and gas executives who knew this narrative was flawed were pressured to accept it through political and regulatory dictat, corporate governance, lawsuits, and shareholder pressure. Many industry participants grew concerned that EV penetration, fuel economy improvements, and biofuel blending mandates would slow gasoline and diesel demand over time. As a result, refining would no longer be a reliable growth engine. Sticking to these “sunsetting” products implicitly meant embracing excess supply and structurally low margins.

Petrochemical production, on the other hand, was expected to grow. Rising living standards and global urbanization would drive demand for plastics and other petrochemical products above the GDP growth rate. With demand expected to rise, global majors sought to convert their hydrocarbon feedstocks into chemicals rather than gasoline or diesel. In doing so, they figured they could create more value per barrel of crude oil feedstock. Adding to petrochemicals’ allure was surging production of light oil and NGLs in U.S. shale basins, which promised years of growing chemical feedstock at ultra-low prices. Structurally lower feedstock prices held the prospect of boosting margins relative to competitors on the global stage.

As usual in the oil industry, nearly all participants embraced the same strategy: favoring investment in chemicals over gasoline and diesel. Thus, a synchronized global petrochemical capacity buildout was unleashed. Polymer inventories bulged, prices fell, and petrochemical margins were destroyed.

The economics are plain to see. For example, Shell’s (SHEL) new polyethylene complex in the U.S. has missed its original return targets thanks to cost overruns and weak polyethylene pricing.

The Integrated Majors’ Petrochemical Buildout

The integrated oil majors’ expansion in petrochemicals over the past few years has been unprecedented.

ExxonMobil (XOM) expanded its Baytown, Texas, refinery by adding new chemical units that sourced Permian NGL feedstock. The expansion represented an investment of $2 billion and included a 350,000-ton-per-year olefin unit and a 400,000-ton-per-year performance polymer unit.

More concerning for the chemical market, ExxonMobil plans to continue its Gulf Coast petrochemical buildout to convert light crude oil and NGLs from U.S. shale into higher-value products. The company plans to spend $20 billion over ten years beginning in 2023.

Shell built its Pennsylvania Petrochemicals Complex outside Pittsburgh. The complex is a massive ethane and polyethylene production operation designed to use locally produced Marcellus and Utica ethane to produce plastic. Its capacity is 1.6 million tons of polyethylene per year. Shell estimates spending $14 billion on the project.

TotalEnergies (TTE) commissioned a one-million-ton-per-year ethane steam cracker for $2 billion. The facility is integrated with Total’s refinery platform. In 2023, the company added a new 625,000-ton-per-year polyethylene unit at its Bayport, Texas, platform for approximately $1.4 billion.

Chevron (CVX) and Phillips 66 (PSX) entered into a 50/50 joint venture to partner with QatarEnergy to build a 2.1 million-ton-per-year ethane cracker and two one-million-ton-per-year polyethylene units in Orange County, Texas. Both are set to start up in 2026. The estimated investment for the project is $14.5 billion.

Saudi Aramco has explicitly adopted a “liquids to chemicals” strategy to maximize the profitability of each barrel of oil it produces. Aramco aims to convert 4 million barrels of crude oil per day into petrochemical feedstocks by 2030. As of 2025, it is around halfway there.

Altogether, Aramco’s investments to date include large-scale crackers and mix-feed steam crackers, which are likely to add more than 10 million tons per year of petrochemical production capacity.

All these—and many other—projects around the world amount to a structural supply headwind that will keep global chemical margins depressed and prevent cycles from the swings they have undergone throughout their history.

China’s Petrochemical Buildout

Over the past few years, China has carried out the most extensive petrochemical buildout in history, amounting to roughly 20 million tons per year at a cost of tens of billions of dollars. Multiple “crude to chemicals” facilities were built on the coast with state support. The objectives in the capacity buildout were to replace plastic imports with domestic production, keep refineries profitable as domestic gasoline and diesel demand slowed due to increasing EV adoption, and bind foreign crude suppliers, such as Saudi Aramco, more closely to China through long-term feedstock deals.

China doesn’t have the benefit of low feedstock costs, but it does benefit from low electricity costs and a lax regulatory environment compared to most global manufacturing regions.

The buildout—which is still ongoing—has been driven by state-owned enterprises, domestic private companies, and foreign operators. The list includes ExxonMobil, CNOOC, Shell, PetroChina, Sinopec, and Aramco. It has led to China’s olefins capacity exploding from approximately 45 million tons per year in 2015 to 145 million tons per year in 2025. To make matters worse for the chemical industry, the country is planning an additional 40 million tons per year of supply through 2030.

China is now the price maker in olefins. However, the country is now beset by overcapacity. But the structural oversupply has increased pressure for exports. This is why low-cost Chinese olefins are flooding the market and may continue to do so for years. So far, the country has not exhibited restraint, even amid persistently low prices, despite calls to rein in “disorderly competition”. China’s continued growth in the sector threatens to put global chemical margins under pressure for years.

Conclusion

Olefin economics are set to be challenged for years. While overcapacity amid lower-than-expected demand has led to a global oversupply, supply is set to continue coming online. China’s production is set to grow steadily through 2030, as shown below.

Source: Reuters, Sept. 22, 2025.

If China’s demand fails to rise by the amount of added supply, excess supply will be exported.

Only plant closures can prevent a glutted market on a permanent basis. There are signs that the downturn has forced some closures, but nowhere near enough to alleviate the oversupply over the longer term.

The upshot is that investors must avoid olefins and stick to other chemical sub-sectors. To help sketch a lay of the land, the next section breaks down the chemical industry into its sub-sectors. Each sub-sector has its unique economics. I believe the brief descriptions can help an investor get their bearings as they attempt to scan the chemical sector for bargain opportunities.

Part II: Chemical Industry Sub-Sectors

There are plenty of chemical stocks to choose from outside the olefins. The chemical industry is comprised of a diverse array of companies that run the gamut in terms of cyclicality, returns on capital, competitive advantages, and other factors.

The sector can be broken into sub-sectors presented as follows. This list is not exhaustive, and some companies operate in multiple sub-sectors. I hope it helps a beginner in the sector find areas within their circle of competence where bargains can be found.

Petrochemical Feedstocks. These are the core building blocks of other compounds. They’re made from crude oil—specifically, the lightest grade, naphtha—and NGLs such as ethane and propane. These feedstocks are used to make the olefins ethylene and propylene, as well as the aromatics benzene, toluene, and xylene. Olefins and aromatics, in turn, are used to make various polymers and solvents. Methanol is another petrochemical building block. It makes formaldehyde and acetic acid, among other compounds.

The key drivers of production are feedstock-product spread, such as the spread between ethane and naphtha. As a global market, product flows are also influenced by changes in inventories and prices across different global trading hubs.

Petrochemicals are highly cyclical. Their prices tend to swing with those of crude oil and NGLs.

Polymers and Resins. These products are formed from petrochemical feedstocks. Polyethylene and polypropylene are plastics used in packaging and consumer goods. PVC is used in construction, while PET is used in beverages. Polystyrene is also used in packaging. Various resins are used in automobiles and electronics.

Like petrochemical feedstocks, profitability depends on spreads between feedstocks and products, as well as the state of global inventories. Recycling plays a role in supply, which reduces the need for petrochemical feedstocks in production. The U.S. Gulf Coast is advantaged due to the presence of large refineries and its proximity to production centers in the U.S. shale basins. Longtime HFIR Energy Income Portfolio holding, Enterprise Products Partners (EPD), is engaged in polypropylene through its downstream PDH units.

Public petrochemical, polymer, and resin manufacturers include Dow, Inc. (DOW), LyondellBasell (LYB), and Westlake Corp. (WLK).

Inorganics and Minerals. This group includes a broad spectrum of chemicals, including chlor-alkalis, chlorine, soda ash, titanium dioxide, and carbon black. Feedstocks for these chemicals are generally mined, so the economics underlying each product differ. Soda ash—previously known from our Genesis Energy (GEL) holding, which recently divested of its soda ash operation—is dependent on the prices of natural trona and other synthetic feedstocks. Titanium dioxide is a pigment used in coatings and plastics. Its economics are tied more closely to housing, construction, and automobile production activity. Carbon black tracks rubber demand as a crucial component in tire production.

Public companies include Tronox (TROX), Kronos Worldwide (KRO), Chemours (CC), and Olin (OLN).

Industrial Gases. Oxygen, nitrogen, hydrogen, helium, and specialty gases are included in this subset of chemicals. As gases, these products are advantaged by long-term take-or-pay contracts, high switching costs, and their mission-critical reliability across their various uses. Industrial gases tend to have more favorable economics than other chemical sub-segments. Their demand is driven by steel and chemical manufacturing, healthcare, and electronics—all of which depend on gases for their production. Capital intensity tends to be high, but contract structures lock in attractive returns.

Public companies include Linde (LIN), Air Products & Chemicals (APD), and Air Liquide.

Fertilizers and Crop Nutrients. Natural gas prices drive the economics of these products. Ammonia, urea, phosphate, and potash industries have generally consolidated into semi-oligopolistic supply sources. Demand is impacted by weather, planting acreage, inventory levels, and export restrictions. New projects tend to be large, so these products are also impacted by the start of capacity additions. Due to price volatility, a producer’s place on the cost curve, as well as its logistics, dictates profitability.

Public companies include: CF Industries (CF), Nutrien (NTR), Mosaic (MOS), and Yara.

Agrochemicals. These are synthesized from other chemicals and include herbicides, insecticides, fungicides, seed treatments, and emerging biological compounds. This sub-segment is heavy on intellectual property and devising new formulations of existing products. Product life cycles, patent cliffs, and regulatory regimes all play a part in product economics. Pricing power and high returns tend to rest with the innovators, while generics producers compete on cost and scale.

Public companies include: Corteva (CTVA) and FMC (FMC).

Specialty Chemicals. This is a broad, fragmented category of diverse chemicals that include performance additives, surfactants, catalysts, mining chemicals, and oilfield chemicals. Calumet’s (CLMT) legacy operations can be found here. Many specialty chemicals are involved in lubrication, corrosion resistance, foaming, and other uses. As such, they tend to add value to other processes and products. They also involve greater innovation and lower commodity-price dynamics. Some specialty chemicals possess significant pricing power. Producers differentiate their products through the cadence of innovation, management of products that make up a chemicals portfolio, technical service, and qualification standards.

Public companies include: Eastman Chemical (EMN), Celanese (CE), Huntsman (HUN), and DuPont (DD).

Coatings, Adhesives, Sealants, and Elastomers (CASE). Producers of these products use solvents, additives, and titanium dioxide to make paints, protective coatings, adhesives, and sealants. Demand is tied to construction, automobile manufacturing, aerospace, and industrial activity. Pricing depends on a company’s ability to pass through fluctuating feedstock costs, as well as regulatory and sustainability trends. Companies compete based on their scale and ability to adjust product applications.

Public companies include: Sherwin-Williams (SHW), PPG Industries (PPG), Axalta (AXTA), and RPM International (RPM).

Consumer and Personal Care Ingredients. This sub-segment includes companies in flavors, fragrances, and nutrition. They incorporate surfactants, preservatives, emollients, conditioning polymers, enzymes, and fragrance compounds into products involved in home goods, personal care, food and beverage products, and nutrition. This sub-sector benefits from relatively stable demand, long customer relationships, and technical formulations that increase switching costs. Scale and innovation enhance economics, and pricing discipline influences margins.

Public companies include: International Flavors & Fragrances (IFF), Symrise, Givaudan, and Croda.

Electronics and Semiconductor Chemicals. These are high-barrier-to-entry products with rigorous purity specifications and significant qualifications for their use. Demand is tied to wafer-fab equipment cycles and other technology cycles. The production process typically requires deep process know-how and the supply of ultra-pure inputs, both of which earn premium financial returns. Customers tend to be sticky, and cyclicality is relatively low. Intellectual property development supports competitive advantages.

Public companies include: Entegris (ENTG) and DuPont (DD).

Performance Materials and Advanced Materials. These are specialized engineering plastics, composites, and silicones. Nylons, PBT, and PC blends, epoxies, and carbon fiber matrices. They serve the automobile manufacturing, electronics, medical, construction, and energy industries. A product’s value depends on its weight, thermal and electrical performance, durability, and regulatory compliance. There is often a risk of supply chain constraints, but margins tend to be durable.

Public companies include: Hexcel (HXL), Huntsman (HUN), and Wacker Chemie.

Rubber and Tire Chemicals. Synthetic rubbers are the largest part of this sub-sector. They rely on the supply and price of butadiene and styrene feedstocks. Additives include antioxidants, accelerators, and process oils. Tire demand is the ultimate driver of price, which is influenced by automobile production, miles driven, and freight activity. A producer’s profitability depends on petrochemical feedstock prices and capacity additions.

Public companies include: Cabot (CBT), Orion S.A. (OEC), PCBL Chemical, and Lanxess (LNXSY).

Part III: The Current Downturn and Prospects for a Recovery

As the global chemical industry works through one of its worst downturns in decades, sales volumes have declined for several years, utilization rates have fallen below 80%, and margins across a broad swathe of producers are hovering around cash cost. For many producers, conditions are akin to a deep recession, even though broader GDP continues to grow.

The downturn has caused earnings of the more cyclical chemical companies to decline for three years in a row, with their stock prices following suit. Expectations of continued earnings weakness keep many of the stocks at multi-year lows.

This business and stock price performance begs the question of whether cyclical chemical companies represent an attractive buy at a low point of their cycle. And if so, how should an investor time an investment? Should they take the plunge now or wait for a macro recession to push chemical stocks even lower?

With full acknowledgement that the downturn has longer to go and chemical stocks are likely to remain weak, I believe equity valuations in a large part of the sector are sufficiently attractive to buy now for a multi-year holding period.

The fact of the matter is that downcycles end; this one will, too, like all the cycles that have preceded it. The inevitable upturn will deliver far higher stock prices and outsized returns for those who invest today, in the depths of the downturn.

Investors seeking to position for an upturn should understand the supply-and-demand factors that led to the current downturn, what will drive the transition to an upcycle, and where to look for opportunities throughout the sector.

Chemical Value Chains

When selecting stocks, investors should view the chemical sector not as a single entity but as a set of “value chains” with their own supply-and-demand dynamics.

Chemicals move across a manufacturing chain that adds value at each step. Starting from raw materials, the industry’s products are developed into base chemical building blocks, then intermediates, then polymers, and lastly, formulated and specialty products. Formulated/specialty products are then sold to end users. There are dozens of core platform value chains. The further down a chain you go, the more specialized and less commodity-like the companies tend to be, and the greater the number of companies that exist to add value from precursor chemicals.

The diversity of value chains makes the chemical sector unique among cyclical commodity sectors. For one, the moves of a single commodity do not determine sector-wide economics the way energy producer results are heavily influenced by oil and natural gas prices, and copper or gold mining results by metal prices.

A chemical operation’s economics are dictated first by the particular value chain in which the company resides and second, by where it stands on that chain.

The existence of multiple value chains means that industry economic cycles differ across chains, as each has distinct supply/demand dynamics, logistical requirements, customer behavior, return characteristics, and so forth.

This isn’t to say that GDP recessions don’t depress earnings in the chemical sector. Of course, recessions lower earnings, and as such, remain a risk. However, a macro recession is not necessary to trigger a downturn in a chemical value chain. Furthermore, a GDP upturn isn’t necessary to spur a recovery in a value chain. Chemical value chain downturns and recoveries can and do occur independently of macro recessions. So investors can sit on their hands waiting for a macro recession to arrive and completely miss out on participating in a full cycle that could deliver outsized returns by buying in the downturn and selling during the recovery.

Factors Driving the Downturn

Today’s downturn in the chemical sector is clearly not being driven by a classic GDP recession. Instead, it’s the result of a nasty combination of overbuilt global capacity, weak industrial end-markets in Europe and parts of Asia, and a long destocking cycle that has reduced orders below end-use demand. The result has been a prolonged downturn that feels like a recession within the industry, even though the broader economy continues to grow steadily.

Just as a GDP recession wasn’t necessary to cause the downturn, a GDP upswing won’t be necessary to drive a recovery. Historically, chemical downturns have ended when inventories in a value chain have normalized and high-cost capacity has been rationalized. Demand does not have to be strong; it simply has to tick higher from the depressed levels specific to a value chain during the downturn. In fact, in the early stages of a chemical recovery, demand is significantly below mid-cycle levels. One of the reasons timing a bottom is so difficult is that recoveries begin during times of still relatively weak demand while supply is still adjusting downward. There is no obvious “all clear” signal, such as a visible surge in demand.

Global Demand Weakness

Demand has been weak across various chemical value chains for various reasons. Tepid industrial demand in major economies has reduced activity in several demand-driving sectors, including construction, autos, electronics, packaging, and consumer durables. This demand weakness has affected various chemical value chains in different ways and to varying degrees. Still, most have seen their sales volumes decline significantly over the past two to three years.

European demand has been particularly bad. The contraction of Europe’s manufacturing base in recent years has reduced demand for polymers, intermediates, coatings, and engineering plastics. At the same time, European chemical producers have suffered an industrial crisis brought about by high energy costs, unfavorable policies, and weak manufacturing activity, all of which have eroded the industry’s competitiveness on the global stage.

In North America, where the macro backdrop is better relative to other regions, higher interest rates and slower housing activity have weighed on value chains for nylon, isocyanates, PVC, and packaging-linked products.

In China, a drawn-out property bust and weak heavy-industry activity have cooled demand for construction-related and freight-dependent value chains.

Another important cause of weak global chemical demand has been an unusually long restocking phase. During Covid and its immediate aftermath, chemical end users over-ordered and built excess inventories in response to supply-chain chaos and rising prices. However, once conditions normalized, buyers flipped to a hyper-conservative posture, drawing down inventories and ordering only what they needed. This behavior persisted much longer than the typical quarter or two seen in a typical recession. The result is that apparent demand has fallen below actual end-use demand for an extended period, amplifying the downturn in volumes and capacity utilization.

Persistent Oversupply

This downturn has been unusually stubborn because the global chemical industry massively overbuilt capacity during the last cycle, particularly in olefins, as covered above.

While olefins are likely to be mired in a downturn for years, other value chains face varying supply situations. In some, new production capacity continues to ramp, reinforcing pressure on trade flows and export prices. Even as demand stabilizes and destocking runs its course, the sheer amount of capacity, especially in Asia, caps pricing power and keeps margins low.

Until enough high-cost capacity exits the system—or demand grows long enough and fast enough to absorb it—the industry will remain in a low-return state. For example, the vinyl and polyester chains are in this group. In other chains, however, supply rationalization has been ongoing for years, and inventories are closer to normalizing.

What Will Spark an Upturn?

The industry’s own adjustment process will end this downturn.

First, inventories across the various chemical value chains need to be normalized. In many chains, this process is well underway. After several quarters of aggressive destocking, order patterns are gradually reverting to more normal behavior, even as demand remains weak.

Second, production capacity must be rationalized. Rationalization can occur in various ways. High-cost assets are shuttered, marginal projects are delayed or cancelled, balance-sheet-strained operators ratchet back on capex, high-growth companies shift to capital preservation, and the industry consolidates. The extent of supply rationalization varies across different value chains, but the process is clearly advanced, particularly among the most stressed commodity producers.

Third, end-user demand will have to grow modestly from a depressed base. Demand tends to grow along with GDP. It will receive an additional boost once destocking is complete. Even if global industrial activity muddles through with low-single-digit growth, chemical producer revenues and margins will stabilize. Any growth will result in positive operating leverage and higher earnings. Even a slight improvement in the volume environment, combined with a smaller base of production capacity and normalized customer inventories, is enough to lift capacity utilization and margins for the survivors. Once utilization and margins rise, a new upcycle can begin.

The Path Ahead

The recovery from this downturn is unlikely to be “V-shaped.” It will more closely resemble a long, uneven climb out of a trough, marked by gradual improvement with sharp divergence between winners and losers.

Global Volumes

On a global basis, volumes are likely to grow modestly over the next few years. A combination of lower interest rates, slowly improving housing and auto markets, and normalized inventory behavior should support low-single-digit demand growth in many chemical value chains.

Given the cyclically low conditions in which many value chains currently operate, modest growth should be enough to prevent conditions from deteriorating further. Even modest growth from today’s depressed capacity utilization levels is likely to translate into meaningful operating leverage, especially for companies that have structurally lowered their costs and rationalized their product portfolios during the downturn.

Pricing and Margins

A recovery in pricing and margins will lag the volume growth, particularly in commodity chemical products traded globally. Olefin chains are the poster child for this dynamic. With so much capacity in Asia, olefin margins will likely remain under pressure for years, while export prices will remain highly competitive.

Other overbuilt, trade-exposed chains will undergo a similar pattern. The initial phase of the recovery is therefore more about volume stabilization and cost absorption rather than a rapid snap-back in prices and margins. Over time, as capacity remains low and demand grinds higher, pricing power will slowly return. However, this is likely to be a multi-year process rather than a quick reset. Some value chains are better positioned to exercise pricing power than others, even among pure commodity producers.

Regional Divergence

There will be stark regional divergences among chemical producers. Producers in the U.S. and the Middle East benefit from structural feedstock advantages and access to global markets. Consequently, they are poised to emerge from the downturn stronger as high-cost European assets are closed or repurposed.

Asia will remain the swing region in many commodity chemicals. New capacity in China will continue to set the marginal barrel in olefins and several other bulk chemical value chains. Investors should expect trade flows and market shares to continue shifting in favor of low-cost regions.

Europe will continue to lose competitiveness in the global chemical market. High-cost European producers are structurally disadvantaged compared to their U.S. and Middle Eastern competitors, which benefit from lower-cost feedstock and less onerous regulations. Energy price spikes and policy uncertainty in Europe have forced several producers to cut utilization, idle production facilities, consider permanent closures, or relocate their operations to countries where they can regain competitiveness. European chemical producers will be forced to migrate toward specialty chemicals, formulations, and niche value chains where they can justify higher costs with innovation, service, and customer proximity. Falling European production is one of the main supply-side factors set to balance various chemical chains in the longer term.

Corporate Strategy

Corporate strategy among chemical producers will reflect the new reality. For one, the growth-at-scale era is probably over. Management teams now emphasize profitability, resilience, and selective growth rather than total volume growth.

Capex plans are being pruned, discretionary “green” projects are being pushed out or rephased, and capex decisions are being viewed through the lens of balance-sheet capacity rather than growth expectations.

Mergers and acquisitions will focus on portfolio upgrades instead of size. Companies will continue exiting structurally challenged commodity assets and add higher-returning specialties. The companies that execute this pivot with discipline are likely to compound value as the cycle turns.

Where to Invest in the Sector

The industry will emerge from this downturn leaner and meaner than it has been in many years. A new upcycle will bring improved margins and higher returns on capital. For several years, industry players are likely to remain disciplined before memories of the downturn fade and more aggressive producers start to build out capacity.

Investors should favor low-cost, feedstock-advantaged producers in supply chains that are regionally constrained, as well as formulation/specialty businesses with genuine pricing power. These franchises are most likely to emerge from their respective value chain recessions with greater market share, stronger balance sheets, and enhanced earning power.

An investor should also focus in areas where demand growth can fill capacity over time. As long as capacity utilization remains cyclically low—as is likely in olefins—returns to shareholders will remain depressed. Producers with high costs and weak balance sheets are higher risk than lower-cost, stronger competitors. However, the survivors among these producers also possess the greatest upside torque to a recovery.

Structurally higher supply may persist in many chemical value chains for some time. Others appear to be on the cusp of a recovery, where the volume and destocking shock has largely run its course. Despite divergent fundamentals across value chains, the prospect of structural oversupply in some chains has worsened investor sentiment toward the sector as a whole, including value chains with stronger recovery prospects. The indiscriminate selling of chemical stocks has created attractive opportunities. Investors should look to invest in low-cost, regionally advantaged, and niche franchises where mid-cycle earning power is being mispriced off trough conditions.

As for what investors should avoid, top of the list is any value chain characterized by structural oversupply. Investors should also avoid high-cost European commodity chemical operations unless they can demonstrate the ability to shift toward higher-margin products.

Lastly, a macro GDP recession is all but certain to reduce chemical demand. Lower demand will cause earnings and stock prices to fall across the sector. However, well-positioned companies in value chains that are already in advanced stages of their downcycle will experience less severe conditions during a recession and undergo more robust recoveries once economic growth returns. Given the risks posed by a recession, investors should favor companies with strong balance sheets that can survive further deterioration in end-market demand.

While recessions are always a risk, market valuations for many chemical producers are currently so depressed that I believe investors can still earn attractive returns over a three to five year holding period, even if a recession intervenes. The key will be to hold positions in the companies most likely to survive, and to avoid investing in the weaker names.

With the cycle mechanics in place, the most useful next step is to ground them in precedent—how prior downturns resolved, and what signaled the inflection.

Part IV: Lessons from Past Chemical Cycles Applied to Today’s Stocks

Many investors are waiting for the onset of a macro GDP recession before investing, even though prices are at bargain levels. They’re doing so to sidestep a selloff that may happen during a recession, or to time their investment at the bottom in anticipation of the subsequent upturn.

Although a recession may happen and likely push chemical stocks lower, investors should consider initiating a position in chemical stocks now.

Recessions are only clear in hindsight and are nearly impossible to predict accurately. Investors waiting for a recession before buying these stocks might miss out on the profits to be had in the eventual recovery.

Second, the industry has already experienced a brutal multi-year downcycle that has impacted the supply side in a macro recessionary manner.

Third, cyclical chemical stock prices are so low that even if they fall further during a recession, the long-term returns they will generate are likely to be satisfactory.

Fourth, and most importantly, the industry’s historical pattern has been to decline and recover in the absence of a macro recession. In fact, each value chain within the industry has its own unique cycles.

My previous article covered the key economic factors that cause downturns and recoveries. This article will present historical examples of chemical cycle downturns and recoveries, both of which occur on a timetable distinct from the broader GDP changes. Once investors realize how some of the harshest chemical downturns have been resolved within the value chains themselves—often while headline macro data is neutral or only slightly positive—they might consider taking the plunge into some beaten-down chemical stocks today.

Titanium Dioxide: Overbuild, Environmental Crackdown, and Forced Discipline

Titanium dioxide is a particularly volatile chemical value chain. The market’s cycles since 2011 show how bad conditions can get within the titanium dioxide chain, even as global macro GDP expands, and how an upturn can begin without a GDP increase.

In 2011, the titanium dioxide market experienced a spike in prices after severe supply rationalization in response to the 2008-2009 recession. The industry reacted predictably to higher prices: it expanded capacity. This time, China took the lead.

Also predictably, the capacity buildout went too far. While the global economy continued to grow, the excess capacity created in 2012 and 2013 caused a sharp drop in titanium dioxide prices in 2014.

The industry downturn worsened in 2015, with operating rates dropping to the mid-60%. Prices declined sharply, making 2015 one of the worst margin years in decades for titanium dioxide producers.

From the peak of the titanium dioxide cycle in 2011 through the lows of 2015, global GDP grew steadily. The industry’s downturn and eventual stabilization were part of an intra-sector adjustment process.

In this case, the adjustment process was triggered by a glut in major producing regions, which caused a decline in global titanium dioxide prices. In China, prices dropped below producer cash costs, forcing formerly expansionist producers to adopt supply discipline.

Adding to the Chinese industry’s woes were stricter environmental enforcement measures. These measures were implemented to address rising pollution levels resulting from the low-cost production process favored by Chinese titanium dioxide producers.

Chinese producers aiming for rapid expansion in response to rising prices adopted a cheaper but problematic “sulfate” production process. This method is older, simpler, and relies on widely available technology.

The alternative method, the “chloride” process, is more expensive and technologically advanced. This process yields a higher-quality product that commands a premium price.

The problem with the rapid growth of the sulfate process is the pollution it causes. The process produces large amounts of acidic liquid waste and other harmful byproducts, including carbon dioxide. Global regulators have cracked down on sulfate plants that couldn’t afford upgrades to cut pollution. They have generally supported replacing the sulfate process with the chloride process. Today, about 55% of titanium dioxide is made using the sulfate process, mostly in China. Newbuild capacity, both inside and outside China, mainly uses the chloride process.

In 2015, about 98% of Chinese titanium dioxide was produced through the sulfate process. The pollution issue was addressed with regulations such as discharge permits, mandatory inspections, and pollutant tax systems for producers using the sulfate process.

Chinese authorities also stopped approving new sulfate plants and required older ones to relocate or shut down. These measures impacted the Chinese industry but had only a minor effect on overall Chinese titanium dioxide production. Consider that in 2015, China produced a total of 2.7 billion tons of titanium dioxide annually. Brokerage reports at the time estimated that only 112,000 tons of the country’s sulfate production was shut down.

Nevertheless, the reduction of capacity and the outlook for fewer newbuild projects helped pave the way for a market recovery.

While Chinese production retrenched during the 2014-2015 downturn, high-cost Western titanium dioxide production capacity was exiting the field. Older European and North American sulfate plants were curtailed or permanently closed. Weaker assets were shuttered, and producers redirected their focus toward selling higher-value titanium dioxide grades to enhance returns.

The supply adjustment process continued through 2016 while demand remained steady. Demand from coatings and plastics end-users didn’t boom, but the supply reduction amid stable demand helped global inventories normalize, and Chinese exports slowed from manic levels during the boom.

The market’s recovery began in earnest in 2017. That year, titanium dioxide prices and producer margins increased to mid-cycle levels. Not the levels seen during the 2011 euphoria, but levels at which the surviving assets could earn their cost of capital.

Throughout the entire cycle, titanium dioxide producer stocks mirrored the market’s progress. Over the 2014 to 2017 cycle, Tronox Holdings shares plunged by 90% before staging a full recovery, as shown below.

Meanwhile, Kronos shares fell 75% before rebounding and then surged 474% from their lows during the 2017 upcycle.

The lesson from the titanium dioxide cycle is clear: the cycle turned not because of an acceleration in global economic growth, but because enough capacity had exited the market while modest volume growth quietly absorbed the remainder. Economic growth in the major global demand centers over this period remained steady, as shown below.

Source: Our World in Data.

Investors who sat on their hands due to concerns about a looming recession missed out on the opportunity to earn outsized returns over a multi-year holding period. The key was to hold, focus on intrinsic value over price, and avoid getting too emotionally involved in the dramatic short-term swings to which titanium dioxide stocks are prone.

Nitrogen Fertilizers: The Export Retrenchment Playbook

The nitrogen fertilizer value chain experienced a similarly unique cycle. In the mid-2010s, the global nitrogen supply complex expanded capacity across ammonia, urea, and UAN. New projects came online, and U.S. producers increased their investments in both brownfield and greenfield projects to displace imports.

By 2016, the outcome was familiar. Spot prices for key nitrogen products plummeted, marginal producers couldn’t cover their cash costs, and nitrogen-related stocks behaved as if the farm economy had fallen off a cliff, even though the demand backdrop was nowhere near a 2008-style collapse. The 2016-2017 dip in U.S. nitrogen fertilizer prices is shown below.

Source: Elaine Kub, “High Fertilizer Prices: History and Future,” Progressive Farmer. Dec. 15, 2021. Red-dotted circle added by author.

AdvanSix (ASIX) made its debut as a standalone public company into this storm, with its October 2016 spinoff from Honeywell (HON). The company has significant exposure to nitrogen through its production of ammonium sulfate, a widely used nitrogen-based fertilizer.,

Like the titanium dioxide market, the nitrogen market did not need an official macro recession to be stabilized. Its adjustment mechanism was a retrenchment in global exports. As nitrogen prices in China fell below marginal cash cost, Chinese urea exports declined. Higher-cost Chinese producers were forced to reduce exports because their economics no longer supported pushing volumes into the seaborne market.

The recovery that ensued provided a tailwind for ASIX’s business results and stock price in its debut as a public entity.

Once again, the nitrogen market recovery was not driven by a significant demand surge or a massive agricultural boom. It was driven by steady, unexciting demand, combined with fewer tons dumped onto the market by the swing exporters. These exporters removed uneconomic capacity from the export pool.

Meanwhile, in the U.S., domestic capacity ramped up as imports fell and global trade flows reshuffled to reflect the new cost curve. ASIX’s stock price rebounded as its ammonium phosphate business improved amid market adjustments.

The situation highlights that when low-cost production along a chemical value chain is concentrated in a specific region, such as China or the Middle East, the key signals for the cycle are not GDP but export volumes, netbacks for marginal producers, and the willingness of swing producers to flood the market despite poor economics. This was true in past examples, and it is still true today.

Nylon and Engineered Resins: Demand Shock Plus Overbuild

ASIX’s other main business segment, its nylon 6 production, has experienced its own unique cycles since the company came public.

When oil prices plunged in 2015 and into 2016, the prices of key nylon feedstocks also collapsed. Meanwhile, weak textile demand caused a margin squeeze for many producers. The pricing and demand downturn for nylon 6—also known as “polyamide 6” or “PA6”—is shown in the chart below.

Source: Wood Mackenzie, Domo Chemicals, “The past, future and present of the polyamide industry.” Jan. 4, 2019.

Heading into 2017, nylon 6 demand firmed amid rising automotive demand. The market grew tighter, and prices shot higher.

Then in 2019, two adverse shocks hit the market in succession. First, regulatory changes to emissions testing in Europe disrupted auto production and supplier ordering patterns. Second, expansion projects already underway in key intermediates did not stop as demand wobbled.

The third shock was delivered by the Covid downturn in 2020. This was the most severe. Global auto production fell off a cliff, freezing nylon-6 demand.

The outcome was a deep sector-specific recession characterized by awful spreads between products and their feedstocks, aggressive price cuts, and producers forced to reconsider what “mid-cycle” prices and margins could realistically be. Not surprisingly, the downturn pummeled ASIX’s financial results. Its stock price followed suit.

A marked pickup in auto demand did not drive the recovery that began at the mid-2020 lows. Instead, the adjustment process involved normalizing automobile build rates from low levels, digesting the projects already in the pipeline, and adopting a much more cautious approach to future capacity expansion. The industry realized that its former growth assumptions were too optimistic and that its capital intensity had to come down.

Tying Historical Precedents to Current Conditions

Today, chemicals are in a deep profit recession driven by persistent oversupply and weak pricing power, not a collapse in volumes. China is playing the familiar role of serial overbuilder and exporter across titanium dioxide, intermediates, nylon, olefins, and other products. Europe is being forced to rationalize as the high-cost producer, as high energy and carbon costs shove plants off the cost curve. End-market demand in housing, autos, and consumer durables is soft but hardly apocalyptic.

History shows that the cure for the current downturn is already embedded in the system: the destruction of marginal capacity, the cancellation of growth projects, and a gradual rebalancing of trade flows. The bad news is that this process is painful. The good news is that a macro shock is not required to start the healing.

Titanium dioxide and similar intermediates are experiencing classic titanium dioxide dynamics, characterized by heavy overbuilding, concentrated Chinese capacity, and significant environmental and regulatory pressure. The path out will look like the last titanium dioxide cycle, featuring closures of smaller Chinese producers, supply rationalization among high-cost Western assets, and modest demand growth playing its usual role. This time, the market will benefit from broad tariffs on Chinese products. Reduced Chinese supply to major importers will bolster the competitive position of the three non-Chinese producers that dominate half the market. The key will be to watch where enforcement tightens and where capacity that was assumed to be permanent starts to disappear.

The parallels between the previous nylon 6 cycle and the current one are obvious. At present, the auto and construction end markets are soft but not collapsing. Chinese capacity and exports have added incremental supply pressure to the market’s softness. The fix will be a combination of demand normalization, the selective exiting of capacity, and underutilization outside China. The pain is already visible in spreads and nylon 6 producer earnings. Notably, a formal recession did not trigger this downturn. Producers simply must reduce capex and remove marginal assets from operation. As they do, the market will rebalance.

A nylon 6 recovery will depend on demand returning to normal in autos and construction, as well as selective capacity shutdowns outside China. It will also require pricing discipline among U.S. producers. A new boom won’t be necessary to trigger a recovery, just a rebound from low activity levels and more cautious capital spending.

What to Watch on Supply

Investors in the chemical sector should monitor changes in capacity and capacity utilization, as well as capex plans among global producers. It will be important to determine whether announced closures in Europe and marginal Asian regions are actually occurring and whether they’re not mere talking points on quarterly earnings conference calls.

Investors will also want to make sure new projects are being outright canceled rather than pushed back a year. They should track whether management teams are truly pivoting from growth narratives to balance sheet repair and cash preservation. When management teams and boards of directors stop emphasizing their secular growth stories and start behaving as if capital is scarce, the likelihood increases that the cycle will resolve on its own.

Investors in chemical producers in the midst of a cyclical downturn should also monitor export volumes and exporter netbacks. The core issue will be whether the volume of Chinese exports flowing into key demand regions is tracking higher, beginning to roll over, or in decline. Additionally, they should determine whether netbacks for Western exporters are stabilizing and improving, or whether these market participants continue to fight for low-margin orders in competitive markets.

Any signs of tariffs, anti-dumping cases, or other trade barriers that alter the economics of dumping are also relevant. For titanium dioxide and nitrogen 6, the implementation of tariffs will signal whether a more typical industry retrenchment is underway in the chemical chains where swing exporters dominate the marginal barrel or ton.

Regarding demand, investors should not simply label it as “weak” or “strong.” Instead, they need to assess whether a chemical value chain cycle is deteriorating or stabilizing. Have order books stopped getting worse? Are signs of restocking replacing hand-to-mouth purchasing behavior? Is there any evidence that customers are accepting price increases in parts of the value chain? All these factors are more important to a cycle’s progress than the latest macro GDP print.

Importantly, chemical stock prices will turn higher before the fundamental upswing is evident in the data. The market will begin to price in the cyclical inflection from downcycle to upcycle when it believes growth capex is effectively dead, enough capacity has been removed, and most of the earnings damage is behind the sector.

Conclusion

Investors waiting for a macro GDP downturn before buying well-positioned chemical stocks at their current bargain prices are ignoring the mechanics that drive the chemical value chain cycles. Many need more pain for the marginal producers, more canceled projects, and more discipline from management teams that spent the last cycle believing their own growth decks. The key for investors is to determine how advanced a value chain is in its adjustment process.

Investors should identify chains where the adjustment process is in later stages, but stock prices don’t reflect this reality. They should invest in the companies best positioned to survive the downturn and thrive in the subsequent upturn. They should also have a grasp on these companies’ normalized earning power during recovery. Everything else is noise—even the stock price. The focus should be on securing a bargain purchase price, not precisely timing a recovery.

We’ve made our picks over the past few weeks and covered some of our new holdings in our articles. We remain on the hunt for attractive prospects. Investors seeking to play a potentially highly profitable capital cycle should consider joining us in initiating positions in their favorite chemical names now. For those interested in going deeper, Chemours, AdvanSix, and the Titanium Dioxide pure-plays are discussed below.

Part V: Chemours: A Capital Cycle Play with Big Upside

Chemours (CC) was formed on July 1, 2015, as a spinoff of DuPont’s (DD) more cyclical businesses. Chemours operates in three businesses: Thermal & Specialized Solutions (TSS), Titanium Technologies (TT), and Advanced Performance Materials (APM). In 2024, the company generated $5.8 billion in sales and $786 million in Adjusted EBITDA. This year, it is on track to earn approximately $750 in Adjusted EBITDA. It has an enterprise value of $5.6 billion. Its Adjusted EBITDA run-

Chemours Overview

Chemours shares have been on a steady decline since 2023, as shown below. The shares are currently priced at a discounted valuation characteristic of a cyclical trough.

The selloff has coincided with the decline in Adjusted EBITDA. This year’s estimated $750 million is down nearly half from the $1.4 billion generated in 2021.

The decline was driven by the ongoing three-and-a-half-year downturn in Chemours’ two cyclical operating segments. These segments have been hit by weak domestic housing and construction markets, Chinese overcapacity, and, most recently, tariffs. The three segments’ annual Adjusted EBITDA contribution since 2014 is shown in the chart below.

When combined, Chemours’ cyclicality is evident.

Given the strong likelihood of a recovery in Chemours’ fundamentals over the next three years and the significant upside potential in its shares amid such a recovery, the time is right for aggressive investors to consider Chemours’ stock for long-term purchase.

Long-term investors in the company must be familiar with its operating segments, their EBITDA generation potential, and their challenges.

Thermal & Specialized Solutions (TSS)

This segment represents Chemours’ refrigerants and thermal-management portfolio. Its core brands are Opteon refrigerants and foam blowing agents, as well as legacy Freon hydrofluorocarbon (HFC) and chlorofluorocarbon (CFC) products. TTS’s end markets are air-conditioning and refrigeration for automobiles and buildings, foam insulation for buildings, and aerosol propellants for niche applications.

The TSS segment is currently Chemours’ profit engine, with strong margins that I believe are both insulated from cyclical forces and are sustainable. The segment’s demand drivers are climate change regulations coming into effect, air conditioning replacement cycles, and new construction.

This segment is a leading beneficiary of a movement by governments to force a refrigerant technology transition away from HFCs and to refrigerants with low global warming potential. In the U.S., the AIM Act is phasing down the production and consumption of HFCs. The leading replacement has been hydrofluoroolefins (HFOs), and Chemours, along with Honeywell, holds a patented duopoly with its Opteon HFO product.

In the third quarter, TTS generated $560 million in sales, a 20% year-over-year increase. The increase was driven by 8% higher volumes and 11% higher prices. The Adjusted EBITDA margin came in at a historically healthy 35%. An 80% increase in Opteon sales drove the performance. Sales of the product now account for more than 75% of TSS segment sales. The impact of Opteon’s growth is illustrated in the table below, which depicts TTS’s third-quarter results.

Source: Chemours’ Q3 2025 Earnings Press Release, Nov. 6, 2025.

Clearly, Opteon’s growth is more than offsetting the shrinkage in Chemours’ legacy Freon and foam volumes, as expected.

Titanium Technologies (TT)

Chemours’ Titanium Technologies segment houses its Ti-Pure titanium dioxide pigment business. Titanium dioxide is a whitening agent and opacifier in paints, cosmetics, and other goods. Chemours is the second-largest producer of titanium dioxide in the global market, which is dominated by four firms. This segment is extremely cyclical, and its downcycle has been responsible for crushing Chemours’ Adjusted EBITDA. However, I believe the titanium dioxide market is near its cyclical trough, and drill more deeply into the topic in a later section below. As the cycle turns upward, it will drive most of Chemours’ Adjusted EBITDA recovery over the coming years.

The TT segment’s demand drivers include pigment demand from the paints and coatings, plastic, paper, automotive, architectural, and construction industries.

In the third quarter, TT generated sales of $612 million but only $25 million in Adjusted EBITDA, representing a 4% margin, due to an 8% decline in global titanium dioxide prices and a 2% decline in the segment’s sales volumes.

Advanced Performance Materials (APM)

This segment is Chemours’ high-end fluoromaterials portfolio. Its main products are Teflon fluoropolymers and coatings, Viton fluoroelastomers, Krytox specialty lubricants, and Nafion ion-exchange membranes.

Its products are used in semiconductors and advanced electronics, automotive applications, and energy transition applications such as hydrogen electrolysis and fuel cells.

APM is less cyclical and enjoys sustained higher margins. However, it is Chemours’ smallest Adjusted EBITDA contributor and is currently being negatively impacted by sluggish industrial end-user demand.

In the third quarter, the segment generated $311 million of sales and $14 million of Adjusted EBITDA. Volumes were down 15% year-over-year.

Investment Thesis

Chemours is a basic long-term capital-cycle play. Its investment thesis is comprised of three main parts, discussed in turn below.

Part 1: HFO Demand Growth

The first part of Chemours’ investment thesis pertains to its TSS segment. The U.S. is undergoing a large-scale transition from HFCs to HFOs. HVAC regulations began requiring the use of HFOs on January 1, 2025. Light automobiles are also already mandated to use HFOs. Medium and heavy-duty automobiles are required to switch by 2028, and industrial HFO uses are being phased in through 2028.

The switch to HFOs will boost TTS Adjusted EBITDA for years. Chemours’ HFOs are priced multiple times higher than its legacy Freon product. For example, auto makers pay $75 to $80 per kilogram of HFO versus $15 to $35 per kilogram of the legacy product. Royal Refrigerants, an online retailer, lists a 25-pound tank of Opteon for automotive use at $890, or $35.60 per pound. It lists a 30-pound tank of automotive Freon at $338, or $11.27 per pound. The improved pricing on HFO translates into more than a 20% increase in Adjusted EBITDA margin for the TTS segment.

As HFOs are more widely adopted and/or as macro demand for the product increases, Chemours will benefit from the additional Adjusted EBITDA. Chemours should be able to grow its TSS revenue at a high single-digit percentage rate. The segment’s Adjusted EBITDA is likely to grow at a rate more than twice that.

Also notable is that as Chemours’ Freon sales have declined, the company has been left with an inventory oversupply of lower-priced product. This has created a temporary drag on the company’s financial results. That drag is dissipating, which will help improve comparable quarterly results going forward.

I estimate that Adjusted EBITDA margins from Opteon sales are in the low-40s%, which is high for the chemical industry. Adjusted EBITDA will therefore receive a significant boost as sales volumes increase.

Assuming a conservative 5.0% annual sales growth from the TTS segment over the next two years, and that the segment generates a 36% Adjusted EBITDA margin, its EBITDA contribution in 2028 would be $830 million.

Part 2: Titanium Dioxide Recovery

As I discuss below, I believe the titanium dioxide market is poised for a cyclical recovery. The TT segment’s Adjusted EBITDA contraction is responsible for the lion’s share of Chemours’ Adjusted EBITDA decline over recent years, so a recovery will likely drive Chemours’ combined Adjusted EBITDA significantly higher.

The TT segment also experienced unexpected downtime due to production outages in the U.S. and Mexico. These outages have been resolved.

The TT segment is working through internal cost reductions that management has billed as structurally reducing costs by $125 million. However, cost savings will likely exceed that amount by a significant margin. Management expects that these initiatives, combined with Chemours’ technological advantages in titanium dioxide production, will make the company one of the lowest-cost producers globally, based on production cost per ton.

Chemours needs only a modest swing in the titanium dioxide cycle to realize a significant boost in the TT segment’s Adjusted EBITDA. Assuming TT revenues revert to a mid-cycle level of $2.5 billion and the company achieves its 10-year average Adjusted EBITDA margin of 20%, the segment will generate $500 million in Adjusted EBITDA. As the cycle inflects higher, Adjusted EBITDA will increase further. In fact, Adjusted EBITDA increases can exceed TT’s historical recovery trends if the segment’s cost-reduction initiatives prove successful.

Part 3: “Other” (An APM Recovery & Data Center Cooling Technology)

A cyclical recovery in Chemours’ APM segment’s end markets will also contribute materially to Chemours’ Adjusted EBITDA recovery over the coming years.

In the third quarter, APM generated $311 million in sales and earned $14 million of Adjusted EBITDA, for a 5% margin. Volumes fell 15% from the previous year. Since 2014, APM’s Adjusted EBITDA margin has averaged 12%, so an improvement in volumes and Adjusted EBITDA stands to add more than $100 million to Adjusted EBITDA annually, for a total normalized segment Adjusted EBITDA contribution of approximately $200 million.

Data center cooling technology is more of a wild card in Chemours’ investment thesis. Nevertheless, it is important because of the significant value it would represent for the company if widely adopted.

For decades, Chemours has demonstrated its ability to innovate, roll out the innovations at scale, and profit as they are commercialized. The company’s newest focal point for innovation is its data center cooling technology.

Chemours has developed a proprietary fluid for two-phase immersion cooling in data centers. Since data center processing speed is directly correlated with heat levels, continued advances in processing will drive increased needs for data centers to dissipate heat. In fact, rising costs for heat reduction will become a major limiting factor on data center growth. Immersion cooling is a promising cooling technology in which data center hardware is submerged in a non-conductive fluid that absorbs heat more efficiently than air.

Chemours is a leader in developing these fluids through its expertise in HFOs. Only it and Honeywell control the patents needed to scale up this immersion cooling technology.

The issue with this technology stems not from its viability, which is proven, but rather from the timing of its implementation. Data centers must be specifically designed to accommodate the technology, so the challenge for a wide-scale rollout will be to partner early with data center owners and developers. At the moment, it appears that a rollout isn’t likely until 2028. As a result, the technology’s economics and long-term potential remain a mystery. Still, Chemours has partnered with digital infrastructure providers and manufacturers to prepare for a rollout.

I won’t take a stab at rendering an Adjusted EBITDA estimate for Chemours’ data center cooling business due to all the unknowns. Instead, I’ll regard the business as a valuable call option to the company’s intrinsic value. What is clear, however, is that the effort has considerable upside potential for Chemours, with minimal downside.

PFAS Liabilities and Other Risks

The ugly part of Chemours is its “per- and polyfluoroalkyl substances,” or “PFAS” liability. This should be front and center for any investor in the company.

PFAS is a class of chemicals known as “forever chemicals” because they don’t break down easily. DuPont began using PFAS in the production of Teflon in 1946. By the 1960s, DuPont knew the chemical was toxic to animals and accumulated in human blood. DuPont’s West Virginia manufacturing plant discharged PFAS into the air and water in the Ohio River Valley, the source of drinking water for more than 70,000 people.

Chemours was saddled with part of DuPont’s PFAS legal and financial burden when it was spun off from DuPont. As such, it is responsible for shouldering a portion of the remediation and other costs.

In 2021, Chemours, DuPont, and DuPont’s agriscience spinoff, Corteva (CTVA), entered into a settlement to resolve legal disputes and established a cost-sharing arrangement to support future PFAS liabilities. The terms of the settlement are spelled out in this press release, a key part of which is excerpted below:

Source: Chemours Press Release, Jan. 22, 2021.

The most recent PFAS development occurred in August, when Chemours, DuPont, and Corteva agreed to an $875 million settlement with the State of New Jersey over PFAS and other environmental claims. Chemours will pay 50% of the approximately $500 million present value of the settlement over 25 years.

In a separate case, a federal judge ordered Chemours to stop unlawful PFAS discharges from its Washington Works facility into the Ohio River, highlighting ongoing reputational and compliance risk.

The greatest uncertainty regarding PFAS litigation stems from personal injury and landfill-related claims if regulators pursue waste operators and manufacturers. There is no reliable way to estimate this potential liability at the moment.

PFAS is therefore an overhang on Chemours’ stock price, and potentially also on its capital allocation. Its most recent financial statements estimate a PFAS environmental remediation liability of $607 million and an accrued litigation liability of $207 million, for a total liability of $814 million as of September 30. In my analysis, I have assumed an obligation of $1.4 billion, which I believe is conservative.

Another risk to Chemours stems from the lapse of its refrigerant patents. Most of the patents that protect its Opteon business will remain in force into the early 2030s. The company is working on new formulations to extend its protection, but there is no guarantee of success.

Chemours also faces execution risk if it continues to add HFO production capacity as planned and demand fails to pan out as the company expects.

Valuation

The Chemours investment thesis hinges on the company’s Adjusted EBITDA margins inflecting upwards over the coming years, as illustrated in the chart.

The TTS segment margins should increase from additional high-margin HFO sales, while the TT and APM segment Adjusted EBITDA should increase more significantly as their respective cycles turn.

I don’t know when APM and TT’s cycles will turn with any precision, but I’m highly confident that, first, they will turn, and second, that Chemours’ stock will move higher well in advance of the upturn. The return upside from Chemours’ current depressed stock price is simply too large for the shares not to move aggressively upon the first glimmer of a sustained recovery.

Chemours is currently trading at an EV/Adjusted EBITDA valuation of approximately 7.5-times, at the high end of its historical range.

Using the Adjusted EBITDA estimates for 2028 for each operating segment, as discussed in my investment thesis above, I expect Chemours to earn roughly $1.5 billion in Adjusted EBITDA before corporate expenses. Applying a 7.0-times EV/Adjusted EBITDA ratio and assuming $3.5 billion of net long-term debt, a PFAS obligation net present value of $1.4 billion, $250 million of corporate overhead, and 150 million shares outstanding, Chemours shares are worth $27 per share, which implies 125% upside from their current price of $12.

In a bull scenario that assumes robust growth of the TTS segment and cyclical-high Adjusted EBITDA from the APM and TT segments (specifically, TTS’s Adjusted EBITDA reaches $925 million, TT reaches $800 million, and APM reaches $250 million), corporate overhead of $250 million, net long-term debt of $3.5 billion, and a PFAS liability of $1.4 billion, Chemours’ Adjusted EBITDA would be $1.7 billion. At a slightly lower EV/Adjusted EBITDA valuation of 6.0-times to account for a cycle-high discount, Chemours’ stock would be valued at $36, for 200% upside.

In a downside scenario that assumes 2028 Adjusted EBITDA of $1.2 billion, a 6.5-times EV/EBITDA multiple, $3.5 billion in net long-term debt, and a $2.5 billion PFAS obligation, the shares would trade at $14, still above today’s price of $12. The margin of safety between price and value that exists in an adverse scenario is one of the reasons I like the shares below $14.

Chemours investors should also keep in mind that the shares have further upside if the immersion-cooling initiative pans out. For perspective, an additional $200 million of Adjusted EBITDA would increase Chemours’ valuation to $35 per share, and $44 per share in the bull scenario sketched above.

Conclusion

The Chemours thesis has some “hair,” to be sure. Shareholders must gauge the PFAS risk and its impact on the company’s valuation. However, the issue has weighed on Chemours’ market valuation in the past. It continues to do so, and even if it persists, it’s unlikely to prevent the shares from rallying amid a cyclical recovery. Consider, for example, that in the 2017-2018 timeframe, Chemours shares traded above $50 at a 6.5-times EV/EBITDA valuation on $1.4 billion of Adjusted EBITDA.

This time around, I believe a price above $30 is achievable in the next three years, for a compound annual total return of 37% for investors buying today at $12. Such a return should be more than satisfactory for aggressive investors who have the patience to hold through the inevitable volatility in the share price. Given these returns, I believe investors should consider buying Chemours shares today.

Part VI: AdvanSix: An Opportunity to Buy at Cyclical Lows

AdvanSix (ASIX) was spun off from Honeywell on October 1, 2016, to create a company that could focus on pursuing its unique growth strategy. ASIX occupies a low-cost position in several niche chemical products. The company’s products face an oversupply and weak demand, which is removing capacity. Prices are currently unsustainable, and ASIX is positioned to thrive once conditions improve.

The stock has trended lower since hitting its last cyclical peak in 2022.

Stocks like ASIX generate the highest returns when they’re bought at cyclical lows, when industry conditions and investor sentiment are in the dumps. That’s where ASIX is today, which makes its stock an attractive long-term buy.

ASIX Overview

ASIX operates an integrated chemical manufacturing chain with five production sites across the U.S. The company converts cumene, ammonia, sulfur, and other feedstocks into nylon 6 resin, caprolactam, ammonium sulfate, and various phenol and acetone-based intermediates. Through its vertical integration, it captures value at each step of the production chain, lowering unit costs and improving margins.

Nylon 6 & Caprolactam

Nylon 6 and caprolactam account for approximately 41% of ASIX’s revenue. The split is 23%/18% between nylon and caprolactam. Plant nutrients account for 30% of revenue, while various chemical intermediates account for the remaining 29%.

Approximately 90% of ASIX’s sales take place in the U.S. Its customers operate across U.S. industry in construction, fertilizer, agrochemicals, plastics, solvents, packaging, adhesives, and electronics. Its U.S.-centered operations provide an additional competitive advantage from lower transportation costs and logistical advantages relative to global competitors selling in the U.S. ASIX’s U.S. weighting renders it exempt from the reciprocal tariffs that have negatively impacted its domestic competitors, most of which are large, diversified chemical companies.

ASIX’s products are derived from the chemical chains illustrated in the graphic below.

Source: AdvanSix 2024 10-K.

Nylon 6 is used to make fibers for textiles, automotive parts, carpets, clothing, and engineering plastics such as gears and bearings. Its strength and heat resistance make it an effective electrical insulator, while its durability makes it suitable for packaging.

Caprolactam is the key feedstock to nylon 6. ASIX is the global low-cost caprolactam producer, which confers a durable competitive advantage as long as end markets are not glutted, as they are today. The caprolactam market is consolidated, with the top three producers, Fibrant, BASF, and Sinopec, holding more than 30% market share.

As in other chemical segments, global supply capacity for nylon 6 and caprolactam has expanded significantly in recent years, with China leading the charge. At the same time, global demand has been weak. The combination of rising supply and tepid demand led to price declines. Low prices for both caprolactam and nylon 6 have driven margins and capacity utilization lower since 2023. ASIX provided the following data on the nylon market in its third-quarter earnings call presentation.

Source: AdvanSix Q3 2025 Earnings Presentation, Nov. 7, 2025.

The removal of high-cost supply will drive an initial recovery. The recovery will progress as capacity utilization rates increase.

The outlook is more constructive over the longer term. Nylon 6 and caprolactam are expected to grow at a mid-single-digit rate through the early 2030s, driven by higher demand for auto parts, plastics, electronics, and textiles.

Ammonium Sulfate

The Raschig process by which ASIX produces nylon 6 throws off significant volumes of ammonium sulfate, which the company sells as fertilizer. Ammonium sulfate is nitrogen-rich, providing plants with the nitrogen and sulfur they need to grow.

Ammonium sulfate’s near-term outlook is brighter than nylon’s, as end markets are not glutted. Ammonium sulfate is also expected to grow in the mid-single-digit percentage range over the coming years, driven by higher demand from agriculture. Agricultural demand from year to year depends on crop prices and planting intensity.

Sulfate demand has remained robust even in recent quarters. ASIX is currently transitioning its product toward “granular ammonium sulfate,” which is easier to spread, slower-releasing, and has higher sulfur content than common substitutes. Due to its various benefits, the granular product is sold at a premium.

By the end of 2025, ASIX will have transitioned 72% of its ammonium sulfate production into higher-margin granular form. The company has dubbed the transition to granular its “SUSTAIN” program. The program is aimed at increasing the company’s granular ammonium sulfate capacity by 200,000 tons, which fetches a premium of $75 per ton. The premium stands to increase ASIX’s mid-cycle Adjusted EBITDA by more than $15 million annually.

ASIX’s SUSTAIN program has consumed most of its growth capex in recent years. The project is slated for completion in 2026, and capex should decline in 2027 and beyond.

Chemical Intermediates

In addition to ammonium sulfate, ASIX’s nylon 6 manufacturing process throws off various chemical intermediates that the company also sells. These products include phenol, acetone, and other co-products. Growth from these chemical intermediates is expected to track in the low single digits over the coming years.

ASIX benefits from structurally higher acetone prices and margins attributable to U.S. antidumping tariffs. Imports have declined from 230,000 tons in 2018 to 64,000 tons in 2024, driving acetone-propylene spreads from $0.10 per pound to a sustainable range of $0.15 to $0.20 per pound. The larger spread stands to add approximately $30 million to ASIX’s mid-cycle Adjusted EBITDA.

Undergoing a Cyclical Downturn

To appreciate the extent of the downturn in which ASIX finds itself, consider that in 2022—which can be used as a benchmark for a high-margin year—ASIX generated $1.9 billion in revenue and $308 million in Adjusted EBITDA, for a margin of 15.9%.

Conditions deteriorated dramatically beginning in 2023. That year, a 22% decline in selling prices amid flat volumes sent revenues down to $1.53 billion. Adjusted EBITDA fell to $154 million, for a 10% margin. In 2024, revenue was flat while Adjusted EBITDA declined to $142 million, resulting in a 9.4% margin.

The downturn has persisted in 2025. In the first nine months of the year, ASIX reported $1.16 billion in revenue—down 2% from the 2024—and $132 million in Adjusted EBITDA, for a margin of 8.8%. Moreover, margins have trended lower. In the third quarter, ASIX’s Adjusted EBITDA margin declined further, to 6.6%. The culprit of the margin decline was lower nylon 6 volumes. Looking ahead, the fourth quarter is the company’s seasonally weakest. Prices remain low, so margins will remain weak.

ASIX’s capex has been high in recent years to fund its SUSTAIN program investments. Capex is slated to remain high in 2026, then decline in 2027 and presumably thereafter, as shown in the slide below.

Source: AdvanSix Q3 2025 Earnings Presentation, Nov. 7, 2025.

Once ASIX completes its growth projects, it will benefit from increased operating cash flow and lower capex, boosting free cash flow. The higher profit margins, returns on capital, and free cash flow resulting from ASIX’s recent capex hold the prospect of pushing the company’s profitability above previous cyclical highs over the coming years.

Despite the higher capex, ASIX has remained free cash flow positive in 2025. The $32.3 million in free cash flow it has generated year-to-date, after adjusting for working capital changes, is equivalent to $1.20 per share.

ASIX’s balance sheet is strong, with $250 million drawn on its revolving line of credit and equity of $824 million.

Attractive Investment Characteristics

ASIX shares trade at a 4.5% dividend yield at their current price of $14.40. The dividend is sustainable even at today’s market conditions, which are characteristic of a cyclical low. At its current trailing-twelve-month Adjusted EBITDA of $142 million, the company should be roughly cash flow neutral in 2026, assuming the $110 million of capex indicated in management’s guidance. The company’s $0.16-per-share quarterly dividend should be safe barring a further deterioration in end-market conditions.

The company’s competitive position is superb, albeit in a pure commodity market. ASIX benefits from its position as the leading global low-cost producer of caprolactam and Nylon 6. It derives its competitive advantage from its integration of the entire nylon 6 chemical production chain. ASIX’s competitive advantage is durable because its foreign competitors are unable to replicate its production configuration, logistics, and cost advantages. The upshot is that ASIX occupies a dominant position with BASF in U.S. caprolactam and nylon 6 production. The company’s status as a low-cost producer enables it to remain profitable at lower prices than its competitors while also running at higher capacity utilization rates.

ASIX is also competitively advantaged as a low-cost ammonium sulfate producer. It owns and operates the largest production facility in the U.S.

The company derives another competitive advantage from low natural gas supply costs. Natural gas is a raw material in the production of caprolactam and ammonium sulfate, as well as a source of energy for the company’s production facilities.

At the moment, the ammonium sulfate market is relatively healthy. The segment will serve as ASIX’s profit center as the domestic nylon 6 market works off its oversupply.

ASIX’s relatively small size in its industry and its attractive, sustainable, low-cost position in niche chemical markets in which producers earn attractive full-cycle returns on capital make it an attractive acquisition candidate. If the stock stays at its current price, I believe an acquisition at a significant premium is likely.

Valuation

Given ASIX’s trailing-twelve-month Adjusted EBITDA of $142 million and an enterprise value of $770 million, its shares currently trade at 5.5-times EV/Adjusted EBITDA—at a low point in the nylon 6 cycle. This low multiple fails to discount any improvement in the company’s financial results going forward, despite the likelihood of a cyclical recovery.

On a normalized mid-cycle Adjusted EBITDA of $200 million, ASIX trades at an EV/Adjusted EBITDA multiple of 3.9-times. A proper valuation at that point would apply a 6-to-8-times multiple, for a stock price of $30 to $45 per share. The lower bound of this value range is equal to the company’s book value per share and stands more than 100% above the current stock price.

I estimate that ASIX can generate cycle-high Adjusted EBITDA in the $250 to $300 million range. On that figure, the stock trades at a 2.8-times EV/Adjusted EBITDA.

Cycle-high Adjusted EBITDA is also consistent with earnings per share of $4.70 and free cash flow per share of $5.10. Applying a ten-times multiple puts the cycle-high share price at around $50. Such a price is consistent with ASIX’s previous cyclical high price achieved in 2022. That year, the company earned Adjusted EBITDA of $308 million and diluted earnings per share of $5.92.

At five-times cycle peak Adjusted EBITDA, ASIX shares would trade at approximately $40, versus the current price of $14.30.

Another way to look at ASIX’s equity value is that the company’s book value per share stands at $30.45. Assuming it can earn a mid-teen return on capital—as it has in the past—then earnings per share would be approximately $4.50, which is also consistent with a mid-$40s share price at a ten-times P/E.

Risks

ASIX investors risk having to sustain a prolonged downturn in nylon 6. They should therefore be ready to endure lower prices as the nylon 6 cycle bottoms out. Importantly, the company’s heavy weighting in the domestic market, its products’ low-cost positions on their respective cost curves, and its strong balance sheet mean that it will survive the ongoing downturn and benefit disproportionately when the upcycle arrives.

The cycle will eventually turn. High-cost nylon 6 supply is currently operating at a significant loss. As such, it will have to be rationalized through facility closures, idling, and consolidation. Prices are so low that even low-cost producers—including ASIX itself—are moderating volumes and lowering their capacity utilization. Clearly, the current market dynamics are unsustainable for the industry, which makes an upturn all the more probable.

Among the other risks for ASIX investors would be an unexpected falloff in fertilizer demand and significantly higher-than-expected capex, which would reduce free cash flow.

Conclusion

ASIX shares will turn higher well before the recovery in its end markets is clear. Nearly every investor has AI at their fingertips, so the ability to detect a turn in the macro is more widely available than it’s ever been. The only reliable edge an investor can have is time arbitrage over the course of a capital cycle. Since the duration of the downturn is not knowable—its turn is only discernible in hindsight—owning shares in low-cost producers is paramount to a successful investment outcome. This is what an investor obtains with ASIX.

In capital cycle investing, the best times to buy are when the outlook is bleak. ASIX investors should adopt a three-year investment horizon and be prepared to hold until the recovery takes effect. Short-term paper losses are part of the process. But the massive returns on offer for those who can buy make them well worth the temporary inconvenience.

Now is a good time to buy beaten-down cyclical chemical names, and ASIX is one of the best.

Nylon is one expression of the cycle. Titanium dioxide is another—often more volatile, and often faster to reprice once supply finally tightens.

Part VII: A Titanium Dioxide Market Recovery Appears Imminent

The titanium dioxide market is in a historic downturn that has gone on for three-and-a-half years. Over that period, the negative cyclical forces have gone a long way toward reducing supply to today’s tepid demand conditions. In the process, they’ve set the stage for a recovery.

The titanium dioxide market’s brutal downcycle has forced significant changes, improving its macro outlook. The downcycle flushed out weak industry players, forced larger players to operate in a more disciplined manner, reduced producers’ inventories, brought about anti-dumping regimes in key importing regions, and curtailed production capacity to a point where even a slight demand uptick will drive titanium dioxide prices higher.

These and other market changes have laid the groundwork for a cyclical recovery over the next few quarters, assuming demand remains flat or improves. If the worst of the downturn truly is in the rearview mirror, the industry should enter the 2026 contract season with tighter supply and better pricing prospects than many headlines suggest. If prices or volumes show any indication of ticking higher, their stocks are likely to surge in anticipation of a recovery.

Temporary Factors Drove Third-quarter Weakness

Third-quarter results are in for the major titanium producers, Tronox, Kronos Worldwide, and Chemours. The results show that market conditions during the quarter were far weaker than these companies had expected earlier in the year. Notably, several of the most significant factors contributing to the weakness were temporary in nature.

For one, Venator’s insolvency caused it to liquidate its titanium dioxide at below-market prices. The surge in supply amid tepid demand led to prices declining more than expected. The situation was particularly acute in Europe, where Venator and Kronos have a significant presence. In their third-quarter earnings conference calls, the management of the major titanium dioxide producers alluded to the fact that this inventory liquidation will persist through the end of the year. Once it has run its course, however, the supply-demand picture will tighten, and prices are likely to rise.

Aside from Venator, other distressed global producers have dumped their titanium dioxide inventory onto the market regardless of price. Prices can recover once this excess supply is absorbed.

Each of the major market participants has slimmed down its inventory levels, consistent with late-cycle behavior in commodity cycles. Lower inventories tend to shorten the remaining duration of the downturn. Any uptick in demand in these conditions can cause prices to surge.

Another temporary negative factor that depressed the market in the third quarter was India’s stay of anti-dumping tariffs on titanium dioxide. The stay allowed low-priced Chinese producers to surge their exports to India. The supply surge weakened Asian titanium dioxide prices, with negative knock-on effects on the global market.

Fortunately, India’s stay was imposed by a court on procedural grounds. As such, it’s likely to be reversed over the coming weeks. India is the second-largest importer of titanium dioxide, so import tariffs will strengthen supply and benefit producers outside China.

Another temporary negative during the quarter was the downstream destocking by customers in the coatings industry. These customers cut their titanium dioxide orders deeper and earlier than usual. However, Tronox management indicated that order patterns have already begun to normalize in the fourth quarter. Once the working capital adjustment among downstream customers is complete, demand for titanium dioxide feedstock can improve.

The Supply Side Will Drive the Recovery

Commodity market recoveries begin when supply has fallen in line with or below demand. The titanium dioxide market appears to have reached this point.

The main factor behind the market’s recovery potential is the unprecedented amount of global production curtailments. Literally every producer of size has either permanently shut down or idled capacity. Furthermore, the production facilities in operation today have cut back on volumes.

All in all, several management teams have cited 1.1 million tons of production curtailments in a global market that stands at approximately 10.0 million tons per year. The supply adjustment bodes well for prices going forward. It gives me the confidence to state that a recovery isn’t a matter of “if,” but of “when.”

The second most important factor driving a recovery in the titanium dioxide market is the imposition of anti-dumping measures. These measures have been enacted in the U.S., the European Union, Brazil, Saudi Arabia, and elsewhere. The measures are intended to increase the industry’s competitiveness relative to Chinese competitors, which benefit from low coal-based electricity costs, lower labor costs, and more lax environmental regulations. Chinese producers also receive government subsidies that make them even more price-competitive on the global stage.

The anti-dumping measures are having a significant impact. In the U.S., Section 301 tariffs have reduced titanium dioxide imports to 90,000 tons per year in a market that consumes one million tons per year. Meanwhile, anti-dumping measures imposed by the EU, Brazil, and Saudi Arabia are set to protect a market that consumes a combined 1.2 million tons per year.

Anti-dumping measures put in place to date have eliminated approximately 800,000 tons per year of low-cost titanium dioxide from the global market. To illustrate their impact, Tronox included this slide in its investor presentation. While the measures don’t eliminate Chinese imports, they do significantly reduce them.

Source: Tronox Q3 2025 Earnings Presentation, Nov. 6, 2025.

Since the anti-dumping measures are all being applied at the same time, they’re putting a major dent into Chinese dumping. This will be a major factor in a titanium dioxide price recovery.

With fewer export channels, titanium dioxide inventories are piling up in China. Higher inventories are depressing domestic prices and forcing a supply rationalization that includes permanent closures of production facilities and consolidation among weaker producers. The reduction of low-cost supply will benefit the titanium dioxide market for years.

Another positive development that will hasten a recovery is Venator’s insolvency. Venator, which declared insolvency in May, had been the fifth-largest global titanium dioxide producer in a market where the top five producers accounted for more than 50% of global output. Venator’s exit whittles down the number of dominant producers to four. The removal of the fifth-largest producer will allow the remaining four to gain share. Kronos is particularly well-positioned. It is the best positioned to win market share from Venator’s exit from Europe and has acquired Venator’s 50% interest in the U.S. Louisiana Pigment Company.

Venator’s exit will reduce the urgency among the remaining major producers to undercut each other based on price. In effect, it’s a step toward oligopoly in the industry, just as trade measures are removing a large share of the lowest-cost supply. The market can enter 2026 with far more favorable competitive dynamics for producers than it entered 2025.

Another positive outcome from the downcycle has been that large titanium dioxide buyers increasingly favor larger producers as suppliers. After more than three years of reliability issues, insolvencies, and supplier plant shutdowns, buyers are committing to the “Big Three” outside of China, namely, Chemours, Tronox, and Kronos. These dominant producers are insulated against broader market turbulence through their partial or full vertical integration. They operate in multiple regions, can better meet customers’ product specifications, and can swing volumes across their various plants.

The shift toward the larger producers will enable them to emerge from the current downturn with greater market share and better line of sight regarding contract volumes and duration.

Altogether, these factors are likely to drive titanium dioxide prices higher. Even a low-to-mid-single-digit price increase will push the major producers’ operations into positive free cash flow territory. At that point, their survival will no longer be in question, and their stock prices should trade significantly higher.

Risks

These are among the most volatile stocks in the market, so investors should expect significant price swings. Positions should be sized to withstand the inevitable large selloffs, which I expect to be severe, yet temporary, before a market recovery carries the entire group much higher.

For Kronos and Tronox, dividends are at risk if the market doesn’t turn higher over the coming quarters. Buyers of these stocks should not count on the continuation of dividends.

From a fundamentals perspective, the largest risk is a decline in titanium dioxide demand from today’s already weak level. Several demand variables could cause volumes to decline and force further retrenchment among global titanium dioxide producers. Foremost among these risks are a falloff in U.S. housing activity and a deepening European economic contraction.

Lastly, a recovery could be put at risk if policies in importing nations dilute the impact of anti-dumping measures.

Conclusion

Titanium dioxide is a cyclical market that is possibly probing its cyclical trough. Investors looking to play a recovery from a deep cyclical downturn should consider the titanium dioxide producers. In order of risk, from lowest to highest, investors should consider Chemours, Kronos, and Tronox. The list is reversed in terms of upside potential from current prices. A basket approach, in which an investor holds all three at whatever weighting makes sense, is also worth considering.

The cyclical trough is the time when sentiment among market participants and observers is at its lowest, and headlines about the industry are the scariest. It’s also the hardest time to step up and buy. Nevertheless, I’m confident that it is only a matter of time before the titanium dioxide cycle inflects. When it does, long-term investors who can hold through the selloffs and make it to the other side will be amply rewarded with multi-bagger returns.

With the market backdrop set, we can move to a higher-beta expression of the same cycle, where company-specific actions can magnify the recovery.

Part VIII: Tronox: Improving Prospects in 2026 and Beyond to Drive Shares Higher

Tronox is a recovery play on the titanium dioxide market with added kickers from company-specific developments. I’ve followed the company’s ups and downs since 2012, and I believe this is a good time to initiate a long position.

Today, finds itself in one of its industry’s most protracted downturns. The downturn’s length is attributable to aggressive new Chinese competitors and tepid global demand. Tronox’s revenues have trended lower since 2021, tracking the downturn in the titanium dioxide market.

Historically, the company has exhibited some of the most extreme cyclical price swings of any company I know. The chart below illustrates how closely its share price follows the ups and downs of titanium dioxide prices. It depicts the market’s swings that occurred from 2010 to 2021.

Sources: Venator May 2023 Investor Presentation, Yahoo! Finance Oct. 28, 2025. Black-dotted lines and highlights added by author.

Today, I believe Tronox is in another cyclical trough. While the duration of the trough can’t be known with any degree of precision, improvements within the company are set to boost EBITDA and cash flow in 2026, which, in turn, should support its stock price. By the time the titanium dioxide market shows signs of a recovery, I expect Tronox shares to be bid far above their current price.

Investment Thesis

Tronox’s investment thesis has three parts.

First, protectionist anti-dumping measures are likely to benefit titanium dioxide producers outside of China in 2026.

Second, Tronox’s cost reduction initiatives will boost EBITDA and cash flow in 2026. Third, the titanium dioxide market will recover once inventories are depleted and demand returns, driven by increased construction spending and growing GDP.

Third, after the company’s EBITDA and cash flow improve in 2026, I expect the titanium dioxide market to recover in 2027. Even a mild recovery will turbocharge the stock’s upside move.

I expect these factors to send Tronox shares more than 100% above their current price over the next two years, and even higher over subsequent years. Tronox is most appropriate for long-term holding, and investors must be prepared to stomach the inevitable volatility during their holding period.

Titanium Dioxide Market and Protectionist Measures

Titanium dioxide is the primary pigment used to whiten paints, coatings, and plastics. Its demand is tied to activity in construction, housing, automobile manufacturing, and to broader GDP.

The titanium dioxide market is dominated by four firms, which combined account for around 50% of the global market. These are the China-based LB Group, Chemours, Tronox, and Kronos. Smaller operators based in China and Europe account for most of the remainder of the market. Chinese production accounts for approximately 60% of total global production.

The titanium dioxide market is expected to grow significantly through 2030, as shown in the chart below.

Source: Grand View Research.

LB Group, based in China, is the world’s largest producer of titanium dioxide. It has grown market share at the expense of its three Western competitors. Its low-cost electricity and labor, coupled with relatively lax regulatory requirements, give it a competitive advantage. However, increasing trade protection measures in the EU, Brazil, Saudi Arabia, and the EAEU (comprised of Russia, Kazakhstan, Belarus, Armenia, and Kyrgyzstan) have sought to level the playing field between the Chinese producers and their global peers. In the U.S., while titanium dioxide imports haven’t been targeted directly, they are subject to the 25% “Section 301” tariff overseen by the U.S. Trade Representative.

Most titanium dioxide tariffs have been enacted throughout 2025. The measures have already been effective. By May 2025, China’s titanium dioxide exports had already fallen by approximately 20%.

Additionally, titanium dioxide markets in consuming countries are set to improve, with lower supply amid stable demand set to increase prices. Before protectionist measures are implemented, major titanium dioxide buyers tend to front-load their purchases from low-cost producers that will be subject to tariffs. These purchase orders dampen demand after the protectionist measures are enacted. Eventually, however, they are likely to boost prices for producers outside of China. I expect the market to benefit from the measures in 2026 and beyond. If Chinese product has fewer export destinations, LB Group’s margins could come under pressure at home, further weakening its competitive position in the global market.

Cyclical Forces Will Facilitate a Recovery

Excess production amid international tariffs has caused excess titanium dioxide product to flow to the U.S and Japan. Even with tariffs, these countries’ producers can be undercut by Chinese imports, particularly in the standard rutile titanium dioxide grades. However, domestic producers of premium and specialty grades tend to face far less competition from foreign sources. Higher inventories have pushed prices lower. Tronox

The titanium dioxide market will recover in time. Cyclical forces are already at work. Most producers have idled their high-cost plants. Tronox idled its Botlek pigment site in the Netherlands, which accounts for approximately 8% of its production. Chinese producers have idled some capacity amid weak market conditions.

I don’t have any special insight into when this cycle will turn, but I am certain of two things. First, these stocks are best bought for long-term holding when the outlook is at its most grim. Second, the first indication that the market is improving will send these stocks surging, as investors jump on the “all clear” bandwagon.

When the cycle turns and titanium dioxide prices rise, Tronox benefits from being one of the few vertically integrated titanium dioxide producers. It sources approximately 85% of its raw materials used in titanium dioxide production internally.

Vertical integration has advantages and disadvantages in titanium dioxide production. The biggest disadvantage is that mining tends to be a low-return business. But the advantages are considerable. When titanium dioxide prices are high, the prices of the product’s feedstock, ilmenite and rutile, also increase. Raw material price increases put downward pressure on margins for non-integrated producers at the time when their margins should be approaching cyclical highs. Due to Tronox’s vertical integration, its margins and fee cash flow are poised to increase significantly more than those of its competitors during upcycles, facilitating debt reduction and dividend increases.

EBITDA Growth Likely Ahead

Tronox shares are typically valued in the market based on EV/EBITDA multiples. At its cyclically low EBITDA, it trades at 8.5-times EV/EBITDA. EBITDA guidance was revised lower in the company’s second-quarter conference call.

Tronox’s EBITDA is set to increase in 2026. In late 2024, management launched a cost-savings program intended to reduce operating costs by $125 to $175 million in 2025. As of Tronox’s second-quarter earnings conference call on July 31, management was confident it would meet the goal. The cost savings should translate into higher EBITDA in 2026, assuming titanium dioxide pricing doesn’t fall significantly from current levels.

Other factors are likely to boost 2026 EBITDA. Tronox is upgrading its mining operation by moving feedstock production from lower-quality to higher-quality mines in 2026. The switch will increase EBITDA by $50 million and reduce capex by approximately $100 million. Meanwhile, the Botlek plant idling will further reduce operating costs and capex by more than $20 million.

Source: Tronox May 2025 Investor Presentation.

Altogether, I expect Tronox to generate EBITDA of $600 million in 2026, a 38% increase from the $435 million in management’s 2025 guidance. At $600 million in EBITDA, Tronox’s current valuation would represent a 6.2-times EV/EBITDA, which is very low for a company with cyclically low EBITDA. Over the coming years, Tronox shares can benefit from significantly higher EBITDA and margin expansion.

Another way to view the stock’s current valuation is that virtually no improvement in the titanium dioxide market is priced into Tronox’s shares. This makes it even more likely that when the market turns, the shares will surge higher.

Risks

Tronox shares have significant risk. As such, they should be sized at a small level relative to a portfolio. The most significant risk stems from leverage.

The company’s net long-term debt stands at 4.8-times management’s guided full-year 2025 Adjusted EBITDA. This is high, though the EBITDA figure reflects a depressed titanium dioxide market. I expect it to recover beginning in 2026.

Source: Tronox Q2 2025 10-Q.

Tronox faces a maturity wall in 2029. If the titanium dioxide market hasn’t recovered by then, it could face difficulty refinancing its debt.

On September 15, Tronox priced a $400 million offering of 9.125% Senior Secured Notes due 2030. The notes were offered at par.

The main risk to Tronox shareholders stems from a global recession that sends titanium dioxide prices significantly lower. Tronox could be forced into bankruptcy. There is precedent for such an outcome, as the company declared bankruptcy in 2009.

Conclusion

Tronox has also seen some insider buying this year, which adds support to a recovery thesis. The company has already cut its dividend once this year, reducing the quarterly dividend from $0.125 to $0.05. I don’t expect additional cuts given the improving EBITDA outlook in 2026.

With a lot of bad in the rearview mirror—and priced into the stock—and a little good about to come in 2026, I believe Tronox shares are poised to outperform significantly. Looking beyond 2027, a recovery in its end markets could deliver multi-bagger returns. Investors should consider initiating a position now and adding to it on weakness.

Part IX: Kronos Worldwide: Set to Rebound from a Cyclical Trough

Kronos Worldwide (KRO) is experiencing a brutal downturn in the titanium dioxide industry. Lower sales prices and volumes have caused its earnings and cash flow to go negative for multiple quarters over the past few years, including the recently reported third quarter.

The downturn began in 2022, when higher feedstock costs for titanium dioxide producers coincided with weakening demand from major customers. Since then, Kronos and its peers have experienced declining and weak free cash flow.

The weakness was caused by excess supply amid tepid demand. In this environment, KRO’s sales prices struggled to keep pace with rising per-ton costs.

Operating conditions have intensified recently for the entire titanium dioxide industry, prompting additional retrenchment among producers during the third quarter. However, the clear takeaway is that current margins are unsustainable. It is only a matter of time until the market recovers.

Low prices have already led to unprecedented curtailments in global production volumes. The industry’s production capacity has declined. Titanium dioxide inventories are low. Anti-dumping tariffs have removed the primary source of low-cost supply. These and other factors are likely to usher in higher prices. Eventually, producers will have to increase their production volumes, at which point operating leverage will inflect higher.

I expect cyclical factors to usher in a cyclical recovery in 2026. Kronos is likely to enter that period with a strengthened competitive position and enhanced profitability potential relative to its peers. Recovering profits and cash flow will send its shares higher.

Third-Quarter Results Illustrate Trough-Like Operating Conditions

Third-quarter results illustrated the ugly effects of negative operating leverage. The company’s lower sales volumes and lower prices, amid its high fixed-cost structure, squeezed gross margins and cash flow.

EBITDA declined to close to zero. Year over year, it declined from $123 million to $0.6 million. The decline was mostly due to a large one-time gain in the third quarter of 2024 not being repeated, as well as an inventory cost drag unlikely to recur in future quarters.

Unabsorbed fixed costs were the largest non-temporary factor. These are the variable and fixed costs included in the cost of producing titanium dioxide, which grow larger as production capacity declines and less production is spread across a still-high fixed cost base. The breakdown of year-over-year EBITDA changes is illustrated below.

Large unabsorbed fixed costs will reverse from an EBITDA headwind to a tailwind as the company cuts fixed costs and increases capacity utilization. A lower fixed cost base and higher capacity utilization spread lower costs over more units.

Management attributed the company’s poor third-quarter results to significant excess supply in Europe and weak demand from the North American housing sector. These macro factors caused titanium dioxide buyers to hold off on building inventory. The inventory remained at the industry level, pushing down prices. In response to the weak demand and prices, Kronos idled production.

Titanium dioxide prices declined further over the subsequent months, partly due to one-time events such as Venator’s post-insolvency inventory liquidation. Consider that at the beginning of 2025, KRO’s average titanium dioxide selling prices were 2% higher than the year-ago level. After the tariff disruptions in April, conditions turned for the worse. Prices fell as titanium dioxide buyers postponed purchases until tariff uncertainty cleared. In the first nine months of 2025, weak demand led to a 6% year-over-year decline in titanium dioxide prices.

In the third quarter, lower prices and production volumes caused KRO’s operating cash flow, adjusted for changes in working capital, to fall to negative $3.5 million. After $9.5 million in capital expenditures during the quarter, free cash flow was negative $13.0 million. This ugly performance is typical for an industry approaching its cyclical trough.

I expect the company’s cash flow picture to improve over the coming quarters. Lower costs attributable to idled plants and reduced SG&A, coupled with a modest price improvement, will likely enable the company to generate flat to higher free cash flow in early 2026.

Buying Amid the Cyclical Trough

All it takes is a glance at KRO’s stock chart to determine where we are in the titanium dioxide cycle.

The three-and-a-half-year downturn begs the question of whether conditions will inflect from bearish to bullish. And if so, when?

I remain confident that the titanium dioxide cycle will inflect positively, just as it has for nearly a century. I don’t know precisely when, but the preponderance of data on the state of the industry in the third quarter points to an imminent recovery. I discussed the potential for recovery in the titanium dioxide market in my previous article.

Historically, KRO’s shares have rebounded off their cyclical trough after the company reversed its production capacity curtailments.

Kronos may be close to that moment today. In the third quarter, the company operated at 80% of capacity, significantly below its historical normal rate. For example, in the 2015 downturn, KRO’s capacity utilization bottomed out at 86% before the market recovered, and the stock quintupled over the next two years. During the next downturn, in 2020, KRO’s capacity utilization once again bottomed at 86%. In the more recent 2023 downturn, its capacity utilization bottomed at 65%.

The 2023 downturn is instructive. KRO’s stock turned higher once the company announced an increase in capacity utilization. In fact, the third-quarter earnings announcement was the catalyst that sent the shares surging higher.

The chart below shows KRO’s stock price right before the third-quarter earnings announcement hit. Notice the rally that ensued afterward.

The same dynamic was at play in all past recoveries in Kronos’ stock, and I expect the next one to play out in a similar fashion.

In each case, recovering capacity utilization triggered a strong rebound in the stock price, as investors anticipated the implications of the operating leverage inflection on earnings and cash flow during a titanium dioxide market recovery. I expect a similar dynamic to play out again with Kronos at some point over the next few quarters.

Risks

Kronos shares are at risk from continued weakness in the titanium dioxide market. The company could cut its dividend if conditions don’t improve, so the shares should not be bought for their yield. Offsetting this risk is the fact that the entire titanium dioxide industry is under severe strain. Production is dominated by large players, all of whom are curtailing output.

Due to the risks, aggressive investors should consider a small investment in KRO. The shares clearly have multi-bagger potential, so even a small investment can have an outsized impact on a portfolio’s returns over the coming years.

Conclusion

Kronos and its peers in the titanium dioxide market are probing the troughs of the market cycle. These are the most difficult times to buy, but they can also be the most lucrative. Investors interested in a depressed cyclical play with big upside potential should consider Kronos shares. If conditions improve over the coming quarters, as I expect, the shares offer some of the greatest upside in the stock market.

Part X: Conclusion

The cyclical chemical sector is cheap today for reasons that are real. Many are still experiencing conditions of overcapacity, weak demand, and prolonged destocking. But the cure for cyclical pain is already underway. Inventories are normalizing, high-cost supply is exiting, capital spending is being cut, and operating leverage is beginning to reassert itself. These conditions typically mark the very early stages of an upswing.

Ultimately, success in cyclical chemical investing requires appreciation for the sector’s nuances. The chemical sector is not a single trade, but a collection of distinct value chains governed by cost curves and capital cycles. Understanding where each chain sits in its cyclical adjustment process helps clarify when a recovery is likely to begin, how durable it may be, and when to exit as margins peak. Investors who remain disciplined, focus on fundamentals, and endure the inevitable volatility can position themselves for substantial gains as the cycle turns.

Analyst’s Disclosure: I/we have a beneficial long position in the shares of ASIX, CC, KRO, TROX, EPD, GEL, CLMT, HON either through stock ownership, options, or other derivatives.

By: Jon Costello

Chemours (CC) was formed on July 1, 2015, as a spinoff of DuPont’s (DD) more cyclical businesses. Chemours operates in three businesses: Thermal & Specialized Solutions (TSS), Titanium Technologies (TT), and Advanced Performance Materials (APM). In 2024, the company generated $5.8 billion in sales and $786 million in Adjusted EBITDA. This year, it is on track to earn approximately $750 in Adjusted EBITDA. It has an enterprise value of $5.6 billion.

Chemours Overview

Chemours shares have been on a steady decline since 2023, as shown below. The shares are currently priced at a discounted valuation characteristic of a cyclical trough.

The selloff has coincided with the decline in Adjusted EBITDA. This year’s estimated $750 million is down nearly half from $1.4 billion generated in 2021.

The decline was driven by the ongoing three-and-a-half-year downturn in Chemours’ two cyclical operating segments. These segments have been hit by weak domestic housing and construction markets, Chinese overcapacity, and, most recently, tariffs. The three segments’ annual Adjusted EBITDA contribution since 2014 is shown in the chart below.

When combined, Chemours’ cyclicality is evident.

Given the strong likelihood of a recovery in Chemours’ fundamentals over the next three years and the significant upside potential in its shares amid such a recovery, the time is right for aggressive investors to consider Chemours’ stock for long-term purchase.

Long-term investors in the company must be familiar with its operating segments, their EBITDA generation potential, and their challenges.

Thermal & Specialized Solutions (TSS)

This segment represents Chemours’ refrigerants and thermal-management portfolio. Its core brands are Opteon refrigerants and foam blowing agents, as well as legacy Freon hydrofluorocarbon (HFC) and chlorofluorocarbon (CFC) products. TTS’s end markets are air-conditioning and refrigeration for automobiles and buildings, foam insulation for buildings, and aerosol propellants for niche applications.

The TSS segment is currently Chemours’ profit engine, with strong margins that I believe are both insulated from cyclical forces and are sustainable. The segment’s demand drivers are climate change regulations coming into effect, air conditioning replacement cycles, and new construction.

This segment is a leading beneficiary of a movement by governments to force a refrigerant technology transition away from HFCs and to refrigerants with low global warming potential. In the U.S., the AIM Act is phasing down the production and consumption of HFCs. The leading replacement has been hydrofluoroolefins (HFOs), and Chemours, along with Honeywell (HON), holds a patented duopoly with its Opteon HFO product.

In the third quarter, TTS generated $560 million in sales, a 20% year-over-year increase. The increase was driven by 8% higher volumes and 11% higher prices. The Adjusted EBITDA margin came in at a historically healthy 35%. An 80% increase in Opteon sales drove the performance. Sales of the product now account for more than 75% of TSS segment sales. The impact of Opteon’s growth is illustrated in the table below, which depicts TTS’s third-quarter results.

Source: Chemours’ Q3 2025 Earnings Press Release, Nov. 6, 2025.

Clearly, Opteon’s growth is more than offsetting the shrinkage in Chemours’ legacy Freon and foam volumes, as expected.

Titanium Technologies (TT)

Chemours’ Titanium Technologies segment houses its Ti-Pure titanium dioxide pigment business. Titanium dioxide is a whitening agent and opacifier in paints, cosmetics, and other goods. Chemours is the second-largest producer of titanium dioxide in the global market, which is dominated by four firms. This segment is extremely cyclical, and its downcycle has been responsible for crushing Chemours’ Adjusted EBITDA. However, I believe the titanium dioxide market is near its cyclical trough, as explained in a previous article available here. As the cycle turns upward, it will drive most of Chemours’ Adjusted EBITDA recovery over the coming years.

The TT segment’s demand drivers include pigment demand from the paints and coatings, plastic, paper, automotive, architectural, and construction industries.

In the third quarter, TT generated sales of $612 million but only $25 million in Adjusted EBITDA, representing a 4% margin, due to an 8% decline in global titanium dioxide prices and a 2% decline in the segment’s sales volumes.

Advanced Performance Materials (APM)

This segment is Chemours’ high-end fluoromaterials portfolio. Its main products are Teflon fluoropolymers and coatings, Viton fluoroelastomers, Krytox specialty lubricants, and Nafion ion-exchange membranes.

Its products are used in semiconductors and advanced electronics, automotive applications, and energy transition applications such as hydrogen electrolysis and fuel cells.

APM is less cyclical and enjoys sustained higher margins. However, it is Chemours’ smallest Adjusted EBITDA contributor and is currently being negatively impacted by sluggish industrial end-user demand.

In the third quarter, the segment generated $311 million of sales and $14 million of Adjusted EBITDA. Volumes were down 15% year-over-year.

Investment Thesis

Chemours is a basic long-term capital-cycle play. Its investment thesis is comprised of three main parts, discussed in turn below.

Part 1: HFO Demand Growth

The first part of Chemours’ investment thesis pertains to its TSS segment. The U.S. is undergoing a large-scale transition from HFCs to HFOs. HVAC regulations began requiring the use of HFOs on January 1, 2025. Light automobiles are also already mandated to use HFOs. Medium and heavy-duty automobiles are required to switch by 2028, and industrial HFO uses are being phased in through 2028.

The switch to HFOs will boost TTS Adjusted EBITDA for years. Chemours’ HFOs are priced multiple times higher than its legacy Freon product. For example, auto makers pay $75 to $80 per kilogram of HFO versus $15 to $35 per kilogram of the legacy product. Royal Refrigerants, an online retailer, lists a 25-pound tank of Opteon for automotive use at $890, or $35.60 per pound. It lists a 30-pound tank of automotive Freon at $338, or $11.27 per pound. The improved pricing on HFO translates into more than a 20% increase in Adjusted EBITDA margin for the TTS segment.

As HFOs are more widely adopted and/or as macro demand for the product increases, Chemours will benefit from the additional Adjusted EBITDA. Chemours should be able to grow its TSS revenue at a high single-digit percentage rate. The segment’s Adjusted EBITDA is likely to grow at a rate more than twice that.

Also notable is that as Chemours’ Freon sales have declined, the company has been left with an inventory oversupply of lower-priced product. This has created a temporary drag on the company’s financial results. That drag is dissipating, which will help improve comparable quarterly results going forward.

I estimate that Adjusted EBITDA margins from Opteon sales are in the low-40s%, which is high for the chemical industry. Adjusted EBITDA will therefore receive a significant boost as sales volumes increase.

Assuming a conservative 5.0% annual sales growth from the TTS segment over the next two years, and that the segment generates a 36% Adjusted EBITDA margin, its EBITDA contribution in 2028 would be $830 million.

Part 2: Titanium Dioxide Recovery

I’ve written that the titanium dioxide market is poised for a cyclical recovery. The TT segment’s Adjusted EBITDA contraction is responsible for the lion’s share of Chemours’ Adjusted EBITDA decline over recent years, so a recovery will likely drive Chemours’ combined Adjusted EBITDA significantly higher.

The TT segment also experienced unexpected downtime due to production outages in the U.S. and Mexico. These outages have been resolved.

The TT segment is working through internal cost reductions that management has billed as structurally reducing costs by $125 million. However, cost savings will likely exceed that amount by a significant margin. Management expects that these initiatives, combined with Chemours’ technological advantages in titanium dioxide production, will make the company one of the lowest-cost producers globally, based on production cost per ton.

Chemours needs only a modest swing in the titanium dioxide cycle to realize a significant boost in the TT segment’s Adjusted EBITDA. Assuming TT revenues revert to a mid-cycle level of $2.5 billion and the company achieves its 10-year average Adjusted EBITDA margin of 20%, the segment will generate $500 million in Adjusted EBITDA. As the cycle inflects higher, Adjusted EBITDA will increase further. In fact, Adjusted EBITDA increases can exceed TT’s historical recovery trends if the segment’s cost-reduction initiatives prove successful.

Part 3: “Other” (An APM Recovery & Data Center Cooling Technology)

A cyclical recovery in Chemours’ APM segment’s end markets will also contribute materially to Chemours’ Adjusted EBITDA recovery over the coming years.

In the third quarter, APM generated $311 million in sales and earned $14 million of Adjusted EBITDA, for a 5% margin. Volumes fell 15% from the previous year. Since 2014, APM’s Adjusted EBITDA margin has averaged 12%, so an improvement in volumes and Adjusted EBITDA stands to add more than $100 million to Adjusted EBITDA annually, for a total normalized segment Adjusted EBITDA contribution of approximately $200 million.

Data center cooling technology is more of a wild card in Chemours’ investment thesis. Nevertheless, it is important because of the significant value it would represent for the company if widely adopted.

For decades, Chemours has demonstrated its ability to innovate, roll out the innovations at scale, and profit as they are commercialized. The company’s newest focal point for innovation is its data center cooling technology.

Chemours has developed a proprietary fluid for two-phase immersion cooling in data centers. Since data center processing speed is directly correlated with heat levels, continued advances in processing will drive increased needs for data centers to dissipate heat. In fact, rising costs for heat reduction will become a major limiting factor on data center growth. Immersion cooling is a promising cooling technology in which data center hardware is submerged in a non-conductive fluid that absorbs heat more efficiently than air.

Chemours is a leader in developing these fluids through its expertise in HFOs. Only it and Honeywell control the patents needed to scale up this immersion cooling technology.

The issue with this technology stems not from its viability, which is proven, but rather from the timing of its implementation. Data centers must be specifically designed to accommodate the technology, so the challenge for a wide-scale rollout will be to partner early with data center owners and developers. At the moment, it appears that a rollout isn’t likely until 2028. As a result, the technology’s economics and long-term potential remain a mystery. Still, Chemours has partnered with digital infrastructure providers and manufacturers to prepare for a rollout.

I won’t take a stab at rendering an Adjusted EBITDA estimate for Chemours’ data center cooling business due to all the unknowns. Instead, I’ll regard the business as a valuable call option to the company’s intrinsic value. What is clear, however, is that the effort has considerable upside potential for Chemours, with minimal downside.

PFAS Liabilities and Other Risks

The ugly part of Chemours is its “per- and polyfluoroalkyl substances,” or “PFAS” liability. This should be front and center for any investor in the company.

PFAS is a class of chemicals known as “forever chemicals” because they don’t break down easily. DuPont began using PFAS in the production of Teflon in 1946. By the 1960s, DuPont knew the chemical was toxic to animals and accumulated in human blood. DuPont’s West Virginia manufacturing plant discharged PFAS into the air and water in the Ohio River Valley, the source of drinking water for more than 70,000 people.

Chemours was saddled with part of DuPont’s PFAS legal and financial burden when it was spun off from DuPont. As such, it is responsible for shouldering a portion of the remediation and other costs.

In 2021, Chemours, DuPont, and DuPont’s agriscience spinoff, Corteva (CTVA), entered into a settlement to resolve legal disputes and established a cost-sharing arrangement to support future PFAS liabilities. The terms of the settlement are spelled out in this press release, a key part of which is excerpted below:

Source: Chemours Press Release, Jan. 22, 2021.

The most recent PFAS development occurred in August, when Chemours, DuPont, and Corteva agreed to an $875 million settlement with the State of New Jersey over PFAS and other environmental claims. Chemours will pay 50% of the approximately $500 million present value of the settlement over 25 years.

In a separate case, a federal judge ordered Chemours to stop unlawful PFAS discharges from its Washington Works facility into the Ohio River, highlighting ongoing reputational and compliance risk.

The greatest uncertainty regarding PFAS litigation stems from personal injury and landfill-related claims if regulators pursue waste operators and manufacturers. There is no reliable way to estimate this potential liability at the moment.

PFAS is therefore an overhang on Chemours’ stock price, and potentially also on its capital allocation. Its most recent financial statements estimate a PFAS environmental remediation liability of $607 million and an accrued litigation liability of $207 million, for a total liability of $814 million as of September 30. In my analysis, I have assumed an obligation of $1.4 billion, which I believe is conservative.

Another risk to Chemours stems from the lapse of its refrigerant patents. Most of the patents that protect its Opteon business will remain in force into the early 2030s. The company is working on new formulations to extend its protection, but there is no guarantee of success.

Chemours also faces execution risk if it continues to add HFO production capacity as planned and demand fails to pan out as the company expects.

Valuation

The Chemours investment thesis hinges on the company’s Adjusted EBITDA margins inflecting upwards over the coming years, as illustrated in the chart.

The TTS segment margins should increase from additional high-margin HFO sales, while the TT and APM segment Adjusted EBITDA should increase more significantly as their respective cycles turn.

I don’t know when APM and TT’s cycles will turn with any precision, but I’m highly confident that, first, they will turn, and second, that Chemours’ stock will move higher well in advance of the upturn. The return upside from Chemours’ current depressed stock price is simply too large for the shares not to move aggressively upon the first glimmer of a sustained recovery.

Chemours is currently trading at an EV/Adjusted EBITDA valuation of approximately 7.5-times, at the high end of its historical range.

Using the Adjusted EBITDA estimates for 2028 for each operating segment, as discussed in my investment thesis above, I expect Chemours to earn roughly $1.5 billion in Adjusted EBITDA before corporate expenses. Applying a 7.0-times EV/Adjusted EBITDA ratio and assuming $3.5 billion of net long-term debt, a PFAS obligation net present value of $1.4 billion, $250 million of corporate overhead, and 150 million shares outstanding, Chemours shares are worth $27 per share, which implies 125% upside from their current price of $12.

In a bull scenario that assumes robust growth of the TTS segment and cyclical-high Adjusted EBITDA from the APM and TT segments (specifically, TTS’s Adjusted EBITDA reaches $925 million, TT reaches $800 million, and APM reaches $250 million), corporate overhead of $250 million, net long-term debt of $3.5 billion, and a PFAS liability of $1.4 billion, Chemours’ Adjusted EBITDA would be $1.7 billion. At a slightly lower EV/Adjusted EBITDA valuation of 6.0-times to account for a cycle-high discount, Chemours’ stock would be valued at $36, for 200% upside.

In a downside scenario that assumes 2028 Adjusted EBITDA of $1.2 billion, a 6.5-times EV/EBITDA multiple, $3.5 billion in net long-term debt, and a $2.5 billion PFAS obligation, the shares would trade at $14, still above today’s price of $12. The margin of safety between price and value that exists in an adverse scenario is one of the reasons I like the shares below $14.

Chemours investors should also keep in mind that the shares have further upside if the immersion-cooling initiative pans out. For perspective, an additional $200 million of Adjusted EBITDA would increase Chemours’ valuation to $35 per share, and $44 per share in the bull scenario sketched above.

Conclusion

The Chemours thesis has some “hair,” to be sure. Shareholders must gauge the PFAS risk and its impact on the company’s valuation. However, the issue has weighed on Chemours’ market valuation in the past. It continues to do so, and even if it persists, it’s unlikely to prevent the shares from rallying amid a cyclical recovery. Consider, for example, that in the 2017-2018 timeframe, Chemours shares traded above $50 at a 6.5-times EV/EBITDA valuation on $1.4 billion of Adjusted EBITDA.

This time around, I believe a price above $30 is achievable in the next three years, for a compound annual total return of 37% for investors buying today at $12. Such a return should be more than satisfactory for aggressive investors who have the patience to hold through the inevitable volatility in the share price. Given these returns, I believe investors should consider buying Chemours shares today.

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

Weather models showed a substantial increase in heating degree days this weekend. Since the Friday close, ECMWF-EPS has gained ~48 HDDs, and the next 15-days are projected to be colder-than-normal. On a heating demand basis, we estimate close to ~220 Bcf of natural gas demand was added (conservative). If you include the potential production freeze-off, we could be looking at close to 250-260 Bcf of storage delta.

We originally projected EOS at 1.95 Tcf, but the latest update puts us at 1.75 Tcf.

The latest heating demand increase also puts natural gas back to the 5-year average by the middle of February. This is a major change from the previous forecast.

What does the weather look like?

In the Jan 18 ECMWF-EPS 12z update, this is what the weather maps looked like:

ECMWF-EPS TDD Chart

1-5 Day

6-10 Day

10-15 Day

15-Day Cluster

Now what you will notice in the above charts is the massive ridging pattern stretching from Alaska to Greenland. As we explained in past natural gas reports, this is the bull signal you want to see during winter gas trading. The models are projecting that the bull pattern dissipates, but we think model variability continues to “underwhelm” the real bull scenario.

For example, the Eastern Pacific Oscillation or EPO continues to show a 50/50 outlook for the teleconnection signal. As we explained in our last natural gas article, a negative EPO equates to a bullish outlook, while a positive EPO equates to a bearish outlook.

Since it’s the weather models we are talking about here, the variability is notable given the sudden reversal higher from the current “intense” ridging we see.

Here’s a good example of a snapshot of when the Alaska ridge disappears:

Source: Weatherbell.com

We have several issues with this forecast. First, it appears this sudden change in the Alaska ridge is more related to weather model variability as opposed to pattern confidence. As many people in the natural gas trading business will know, weather models tend to “trend,” and given the strong evidence of “intense” ridging we are seeing in the 1-5 day range (higher confidence forecast range), it is better than 50/50 that it continues to trend that way.

In layman’s terms, what I’m saying is that the models are likely underestimating how much cold we eventually get (or not pricing in the increase in natural gas properly). Unfortunately for those trading natural gas, it implies that you just have to take on the weather model variability risk to see real upside. Models should, in theory, keep trending colder.

In addition to this weekend’s bullish development, another bullish development took place that should warrant even higher natural gas prices. The 15-day outlook (latest update) shows the Alaska ridge returning and colder-than-normal weather persisting in the East.

Source: Weatherbell.com

Now if you align this latest outlook with the ECMWF-EPS weekly, you can quickly see that the bullish weather pattern is expected to persist into late February.

15-22 Day

Source: Weatherbell.com

22-29 Day

Source: Weatherbell.com

29-36 Day

Source: Weatherbell.com

It’s hard to believe, but such a weather forecast would push natural gas prices well above $4.5/MMBtu. Let’s discuss the fundamental implications arising from this.

Fundamentals

Sustained cold is the most bullish outcome for the natural gas market during winter gas trading. Normally, we would see a bout of cold, and then the models would trend warmer, but in this case, this looks like a durable cold for longer.

Our natural gas storage model is being conservative at the moment, but if we assume colder-than-normal weather into the end of February, this is what storage would look like:

The above scenario does not require a major polar vortex or an extreme weather event. All this scenario requires is for us to avoid warmer-than-normal temperatures, which is certainly doable. In the event of another extreme weather event, you will see us break the 2022 lows.

In addition to the increase in heating demand, Lower 48 gas production will experience freeze-offs that will materially impact the supply side.

Canadian net gas imports will jump to fill some of the void, but the freeze-off will be dramatic. We estimate at least ~5 Bcf/d of production going offline with more if the cold is sustained.

And because this cold front won’t impact the South much, LNG exports will still operate near capacity, which will further strain natural gas balances.

From a balance standpoint, a production freeze-off coupled with no meaningful disruption in LNG feedgas will materially tighten the natural gas market. Any supply disruption will eat directly into balances, and traders will price that accordingly.

Conclusion

This weekend saw one of the more dramatic turns of events in terms of heating demand change for the natural gas market. The market underappreciated the risk of colder than normal weather and prices are starting to respond accordingly. Despite the jump higher, we think the market might still be too skeptical of the incoming cold. No one can blame traders for wanting to wait for more certainty after all of the weather volatility earlier this winter. But as we’ve said time and time again, the market was trading as if this winter was over, and it certainly was not. We remain long BOIL.

Paying subscribers received our real-time trade alert to go long BOIL on Jan 15. Please consider becoming a paid subscriber.

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

For our latest thoughts on Petrobras, please see today’s article.

By: Jon Costello

Petroleo Brasileiro S.A., or Petrobras (PBR), is Brazil’s national oil and gas company. The company owns and operates exploration and production assets, infrastructure, and 11 refineries. In the first quarter, PBR produced 2.78 million boe/d, split 73%/27% between liquids and natural gas. PBR accounts for 88% of Brazil’s oil and gas production. It also controls 93% of Brazil’s refining capacity. It owns 26 oil tankers, which partially insulates it from the volatility of the global tanker market.

PBR’s economics are relatively straightforward for an operation of its size. PBR’s financial results are dominated by its E&P segment. E&P segment net income typically accounts for 80% to 85% of total corporate net income. Meanwhile, its vertical integration gives it a competitive advantage against domestic refiners.

Analysis becomes more complicated when factoring in the impact of Brazilian politics. The multitude of risks that stem from Brazil’s always fluid political situation call for regular monitoring by PBR investors.

PBR’s U.S. American Depository Receipts for its common shares are listed on the New York Stock Exchange and currently trade at approximately $15. We value the shares in the range of $20 to $25, but a large margin of safety is necessary due to risks pertaining to Brazilian politics and PBR’s long-term production prospects.

For starters, a brief review of PBR’s history helps to grasp the perception versus the reality of risks to the company’s shareholders.

Historical Overview

PBR was founded in 1953 during a global wave of national oil company expropriations. The company was granted a monopoly over Brazil’s exploration, production, refining, and shipping of the country’s crude oil and natural gas. Only the distribution of petroleum products was outside the monopoly’s purview. Upon its formation, PBR was 51% owned by the Brazilian government, while public ownership of its equity was reserved for Brazilian citizens alone.

Unlike other nationalizations in the 1950s—such as those that occurred in Mexico and Iran—Brazil’s establishment of PBR did not involve the seizure of assets from existing private operations. Part of the reason was practical, as Brazil’s domestic oil and gas production was minimal in the early 1950s. Moreover, the Brazilian government already owned existing oil and gas wells, but in 1953, Brazil’s domestic production of 2,500 boe/d represented only 1.5% of its 170,000 boe/d of internal demand, most of which was met through imports.

PBR’s initial assets consisted mostly of a few small refineries. To increase oil and gas production, it would need foreign expertise, so the Brazilian government set it up with a financial structure that attracted risk capital and incentivized exploration.

Over the years, PBR grew irrespective of the Brazilian political regime. By the 1990s, it had matured into a successful, technologically sophisticated company. Its major assets had been built by the company and its partners.

In 1995, as part of a campaign to privatize state-owned industries, the Brazilian government eliminated PBR’s monopoly status. In 1997, Brazil passed its Petroleum Law, which mandated that the Brazilian government would own at least 50% and one share of PBR’s voting capital. The law also established the ANP as PBR’s regulator and allowed the company to retain ownership of its producing fields, as well as its most attractive exploration prospects. Other assets were transferred to the ANP, which allocated Brazil’s exploration blocks to PBR and others.

Despite losing its monopoly status, PBR was able to compete successfully on a global playing field dominated by international majors. In 2006, the company made seminal offshore discoveries that would increase its operating scale and improve its financial performance.

Today, PBR stands as the largest business in Latin America by market cap, with its economic capital mostly in the hands of public investors.

Expropriation Risk is Far Less than Feared

We touch on PBR’s history to differentiate it from its national oil company around the world. Elsewhere in Latin America, for instance, asset expropriations from foreign investors have been common since the 1950s. Recent examples include Venezuela’s expropriations from ConocoPhillips (COP) and ExxonMobil (XOM) under Hugo Chavez and Argentina’s seizure of YPF from Repsol (OTCQX:REPYF). These actions by national governments came with little hesitation even though they clearly violated Constitutional prohibitions on government expropriation of private property. Like other Latin American nations, Brazil has seen its share of regime changes from socialist to capitalist to military dictatorship. However, it has not shown an inclination toward expropriations.

The success of PBR’s capital structure in driving its operational and financial success is one reason why expropriation never made sense. Furthermore, Brazilian government policies successfully supported the nation’s energy investment, infrastructure growth, and consumption since the 1970s. These policies have remained in effect despite the government’s bureaucratic nature and protectionist bent. Through different regimes, they have allowed PBR to operate independently and have made the nation largely energy-independent.

Oil and gas asset expropriations also tend to happen when private owners of a producing entity receive outsized returns relative to the government take. PBR is subject to massive amounts of production taxes and income taxes that it remits to the government. The company’s massive size and world-class assets generate more than enough cash flow to stabilize Brazil’s budget and support its currency while simultaneously generating attractive returns for shareholders to incentivize public ownership and capital market access.

Brazil’s sheer abundance is another factor behind PBR’s success as an independent entity. The nation’s vast size, economic wealth, and resource potential compared to other Latin American nations have allowed PBR to consistently grow its domestic operations by exploiting Brazil’s domestic resources at an increasing scale. Since its growth occurred along with the rapid growth of Brazil’s middle class, the Brazilian government never had the need to change the company’s course.

Political Interference Risk is Over-Hyped

While PBR does not face expropriation risk, it does face constant political risk. The company is subject to political meddling in its top executive ranks and changing tax regimes. Brazil has a long history of endemic corruption in both business and politics, from which PBR isn’t exempt. The most spectacular example was PBR’s “Car Wash” money laundering scandal in 2014, which involved billions of dollars of shareholder losses and ensnared dozens of prominent Brazilian businesspeople and politicians.

Today, Brazil is governed by the leftist Workers Party. The current President, Luiz Inacio Lula da Saliva, or Lula, is not afraid to interfere in PBR’s affairs. As recently as March 8, after he announced a four-month oil export tax that threatens to reduce PBR’s oil exports, Lula pressured PBR’s board of directors to block a $3 billion special dividend the company was set to make to its shareholders. After the dividend was withheld, PBR’s shares traded down 12% that day, just after they had hit a 10-year high fueled by investor optimism regarding PBR’s production growth. Lula’s move caused analysts to worry that the Brazilian government would become more involved in PBR affairs, such as directing spending toward less-profitable renewables projects and social projects.

Then on May 13—in defiance of Lula’s calls for dividend restraint—PBR’s board ended up issuing the special dividend as initially proposed. In response, Lula fired PBR’s CEO. The unexpected move sent the company’s shares down more than 8% that day. As usual after such an event and its associated stock price selloff, analysts voiced their concerns that the CEO’s ouster was aimed at increasing the Worker’s Party’s influence in PBR’s affairs.

Lula nominated Magda Chambriard as the company’s next CEO. Chambriard was part of Lula’s transition team when he returned to power in 2022. She was formerly the head of the ANP, PBR’s regulatory agency. She favors increasing PBR’s downstream investments and steering the company’s future E&P expansion outside of Brazil.

PBR’s share price has been subdued since Chambriard was named CEO in mid-May. Since her appointment, PBR shares have declined by 11%. Their poor performance is primarily attributable to investors’ fear of lower dividend payments.

PBR investors have to be attentive to political interference risk, which will exist as long as the company is controlled by the Brazilian government. As long as it is, PBR’s capital allocation policies will be subject to change on a whim—in a potentially adversely for public shareholders.

Still, political risk to PBR tends to be overstated. For instance, the media chided the company’s incoming management team as being too political when, in fact, the incoming executives have considerable experience and technical expertise. It is clear that they are not mere political appointees. After all, the previous CEO was also a socialist. He was also PBR’s sixth CEO since 2019. The tenure of the current team may also be short, for better or worse.

Other positive indicators pertaining to the Brazilian government’s intentions for PBR include recent financial projections by Treasury Secretary Rogerio Ceron that call for “100% of Petrobras’ extraordinary dividends as the probable scenario.” Brazil’s Planning and Finance Ministry also raised PBR’s annual dividend revenue estimate by $2.78 billion.

Despite the scary headlines, PBR’s plunging stock price, and political wranglings, it appears that the status quo is the most probable case for PBR’s operations, financial performance, and capital allocation.

High-Quality E&P Assets

What PBR has going for it is its world-class portfolio of E&P assets. These assets produce most of PBR’s earnings, so the company’s earning power is largely dependent on their performance. The following chart illustrates their large—and growing—contribution to PBR’s net income since 2012.

Of the company’s E&P assets, deepwater and ultra-deepwater production account for 94% of total oil and gas output. The remaining 6% is produced from mature fields in shallow waters and onshore, as well as from outside Brazil.

Most of PBR’s production is sourced from the pre-salt fields in the Campos and Santos basins offshore in southeast Brazil. “Pre-salt” refers to thick carbonate reservoirs located under water, rock, and a shifting layer of salt along the continental shelf that extend as much as 25,000 feet below the surface of the Atlantic. Billions of barrels of oil reside in the layer of salt, which is around 6,500 feet thick. PBR operates the pre-salt fields in partnership with other oil majors, including TotalEnergies (TTE), Shell (SHEL), CNOOC, and CNPC.

PBR discovered Brazil’s pre-salt fields in 2006. It achieved first oil in 2008 and began commercial production in 2010. That year, the fields produced a total of 41,000 boe/d. Their production has since increased to 1.81 million boe/d in 2023, equivalent to 80% of Brazil’s oil production and one-quarter of Latin America’s oil production. The table below illustrates the importance of pre-salt production in PBR’s E&P asset portfolio.

Source: PBR 2023 Annual Report Form 20-F. Red-dotted line added by author.

Of PBR’s pre-salt basins, the Campos is largely in decline. The basin has yielded dozens of discoveries since 1978, including four giant fields. PBR mitigates the basin’s declines through infill drilling mostly in its post-salt reservoirs.

Source: Empresa de Pesquisa Energetica Brazilian Oil & Gas Report 2022/2023, Dec. 21, 2023.

The Santos Basin, on the other hand, remains promising. PBR expects it to drive companywide production higher over at least the next five years. PBR’s pre-salt production is located in the “Pre-Salt Polygon” shown below.

Source: PBR 2023 Annual Report Form 20-F.

Most of PBR’s pre-salt production is located in the Santos Basin’s Tupi, Buzios, and Meri fields. The Tupi field was the first pre-salt oil field discovered in Brazil. It is the largest deepwater producing field in the world, with proved reserves of more than 8 billion barrels of oil equivalent and production capacity of one million boe/d. Buzios is a one million boe/d field that has been producing commercially since 2017. The Mero Field produces 180,000 boe/d and is expected to ramp to a maximum production of 600,000 boe/d.

Production Growth

PBR’s E&P economics are underpinned by the spectacular productivity of its wells. The company has 30 wells that produce more than 40,000 boe/d each and 15 to 20 that produce more than 50,000 boe/d each.

The productivity of PBR’s pre-salt wells and the prospect of a windfall from a new discovery have allowed the company to allocate vast sums toward exploration. For years, major pre-salt discoveries have resulted in consistently increasing production. The chart below shows the trend in place from 2000 to 2020 and the role of pre-salt production in driving it higher.

Source: Enverus.

Since 2020, however, PBR’s production has flatlined. Production rates from 2020 to the first quarter is shown below.

PBR is counting on its pre-salt assets to offset the decline of its older assets and drive growth higher over the coming years.

Every year, PBR puts forth a five-year plan to its investors that forecasts production and capex. However, each year’s plan changes significantly from the previous year’s plan, reducing the plans’ reliability as guideposts to PBR’s future activities. The latest five-year plan forecasts production growth from 2.8 billion boe/d in 2023 to 3.1 million boe/d. By 2028, the plan calls for 2.4 million of production to come from the pre-salt layer, representing 79% of total production.

Source: PBR 2023 Annual Report Form 20-F.

While PBR’s growth has been extraordinary, the company has routinely missed its own growth targets. We have no reason to doubt PBR’s ability to reach 3.1 million bpd, but its execution history vis-à-vis its production targets would suggest otherwise.

The Looming End of PBR’s Pre-Salt Era

Despite PBR’s plans for production growth, there are indications that its pre-salt production is topping out. Pre-salt crude oil production declines by approximately 10% per year, so without new discoveries, PBR’s total production could face challenges to growth at best and terminal decline at worst.

The prospect of declining pre-salt production is concerning for PBR shareholders. Over time, production at the current rate without new discoveries that boost reserves could result in declining reserve volumes.

PBR’s proved reserve life extends 11.5 years, enough to provide comfort to existing shareholders that intrinsic value is sufficient to cover their investment at the current stock price. But over the next few years, the company will have to extend its reserves further to mitigate the impact of depletion on reserve value, production volumes, and intrinsic value.

PBR has succeeded in replacing its produced reserves for decades. In 2023, it achieved a 150% reserve replacement ratio, which was attributable to the commercialization of the Raia Manta and Raia Pintada fields in the Campos Basin.

Source: Petrobras Form 2023 20-F.

Given the six-to-ten years of lead time and the significant financial investment necessary to develop a new pre-salt field, PBR has to find new large fields to extend its reserves. Recent exploration results have not been good despite efforts led by the world’s most successful exploration companies, from Shell to TotalEnergies to Exxon Mobil. Despite their efforts, the last major pre-salt discovery was made a decade ago.

While the company’s latest five-year plan, announced in November 2023, maintains its capex focus on pre-salt production, changes from the 2022 five-year plan are telling. The 2023 plan calls for an increase in capex but shows no commensurate increase in management’s production forecast out to 2027.

The 2023 plan forecasts $102 billion of capex over the next five years, boosting PBR’s forecasted capex over the 2022 plan by 31% and by 50% from the 2021 plan. E&P capex will comprise 72% of that amount, or $73.5 billion, up from $65 billion in the previous plan.

Of the $73.5 billion of capex allocated to E&P, approximately $66 billion will be spent on maintaining and growing existing plays, while $7.5 billion will be spent on exploration, up from the previous year’s estimate of $6.0 billion. A total of $3.1 billion will be allocated to the Equatorial Margin, $3.1 billion will be allocated to the Southeast Basins, where pre-salt production is located, and $1.3 billion will be allocated to exploration outside of Brazil.

Source: Petrobras 2024-2028 Strategic Plan Presentation, November 2023.

Recent drilling results in the pre-salt Southeast Basins called into question the prospects for PBR’s forecasted $3.1 billion of exploration spending in the region.

Consider that in 2023, PBR has drilled more dry wells, which it abandoned, than producing wells. Of the 17 wells drilled, only two were producing. Dry wells raise risks for shareholders by reducing a company’s capital efficiency and return capital employed while also raising the specter of accelerating production declines.

The disappointing exploration results caused PBR’s partners, including Shell, Exxon Mobil, Chevron, Repsol—and even PBR itself—to relinquish several exploration blocks.

Other factors further complicate future pre-salt exploration. Among them is the rising costs for the floating production storage and offloading vessels necessary to store and transport oil produced offshore in the pre-salt fields. Another is the international majors’ focus on U.S. shale instead of Brazil, as the nation’s offshore prospects are seen as dimming. Environmental concerns have also become an issue. TotalEnergies recently gave up on pursuing exploration after it faced insurmountable difficulties in obtaining drilling permits.

Even PBR executives have also spoken about the decline of pre-salt. No less than current CEO Magda Chambriard declared the pre-salt boom to be “over.” Private energy consultancy Wood Mackenzie also believes that the pre-salt development is nearing its end.

Energy market consultancy Rystad Energy is slightly more optimistic. It expects gross pre-salt production—including gross production from PBR’s partners—to increase from 3.5 million boe/d to approximately 4.0 million boe/d by 2030. It sees production entering terminal decline thereafter.

With pre-salt decline growing more likely, PBR’s diversification of its exploration activities to other areas appears to have a sound rationale. It is shifting its focus toward the Equatorial Margin and recently made an ultra-deepwater find in the region near Guyana. Nevertheless, we doubt these efforts will yield anything close to the bonanza provided by the pre-salt fields.

It may be a sign of urgency to find new discoveries that PBR even considered pursuing new projects in the Amazon River region. Its efforts even received backing from one of Lula’s aides. However, it reversed course after receiving stiff opposition from environmental groups.

Dual-Class Share Structure

Like most public companies domiciled in Brazil, PBR has a dual-class equity capital structure, with common shares that have economic participation and voting rights and preferred shares that have only economic participation. To compensate for the lack of voting rights, preferred shares are required to receive distributions equivalent to 25% of annual net income. Preferred shareholders get priority on all dividend payments and in a change of control situation. As long as more than 25% of annual net income is being distributed, common and preferred shareholders receive an equal amount of dividends.

PBR’s official dividend policy calls for it to distribute at least $4.0 billion in dividends in years when Brent averages more than $40 per barrel. If gross debt is $65 billion or less, PBR will distribute 45% of its free cash flow each quarter as a base dividend. Above those dividend distributions, PBR will pay extraordinary dividends.

PBR began to pay dividends greater than 25% of net income after deleveraging in 2021, after its long-term debt balance fell below $60 billion. In 2022 and 2023, it paid out most of its free cash flow in a combination of a base and special dividends.

When PBR was financially distressed and common dividends were at risk in the 2015-2016 period, the preferreds traded at as much as a 40% premium to the common shares. Under normal circumstances, however, the preferreds trade at a discount, as they lack the voting feature.

The result of this pricing discrepancy is that the preferred shares trade at a higher dividend yield versus the common shares. For example, both shares received $2.07 in dividends over the past twelve months. The preferred shares, at $14.08, trade at a 14.7% yield, while the common shares, at $15.14, trade at a 13.7% yield.

Brazil’s federal government maintains control through its 50.3% ownership of PBR’s common shares, as seen in the pie chart below.

“BNDES” denotes the Brazilian Development Bank, and “BNDESPar” is BNDES Participacoes S.A., the investment arm of BNDES. These entities collectively own 18% of the preferred shares. Since both entities are owned by the Brazilian government, they essentially represent a government ownership interest in the preferred shares.

Altogether, the Brazilian government owns a 37% economic stake in PBR.

The different characteristics of the common and preferred shares make them more suitable for different types of investors. By law, the Brazilian government will maintain its 50%-plus stake in the company. PBR has shown no tendency to dilute either class. The common and preferred share counts have remained constant at 7.442 billion and 5.602 billion, respectively.

The common will benefit if PBR steps up share repurchases, as these are likely to reduce common shares outstanding. However, the preferred are more likely to retain value relative to the common in an inevitable cyclical downturn. They may even receive dividends when the common shares don’t.

Risks

PBR’s financial risk is low. At the end of the first quarter, net debt stood at $43.6 billion, slightly more than one-time the $40 billion of cash flow the company generates at $80 per barrel Brent. Gross long-term debt of $61.8 billion has been on an uptrend that management has indicated it seeks to limit. Long-term debt stands 16% above the year-ago level, while net debt is up 14% since then. Even so, PBR is in the best position by far among major Latin American oil and gas producers.

The debt situation is a far cry from PBR’s former years, when price controls forced the company to take on increasing amounts of debt to fund capex and other expenditures. Today, net debt-to-EBITDA is currently less than one versus 5.2-times in 2015 after the Car Wash scandal, when PBR came close to a technical default. Its long-term debt peaked at $126.2 billion in 2015 but was reduced after $36.7 billion of divestments since 2016 and robust cash flow generation aimed at debt reduction in 2021 and 2022.

One financial risk was that 40% of the company’s debt was unhedged floating-rate debt. Rising interest rates could also increase debt service costs.

Source: PBR 2023 Annual Report Form 20-F

At the end of 2023, 80% of PBR’s gross long-term debt balance is denominated in currencies other than the Brazilian real, with 71% of long-term debt denominated in U.S. dollars as of the end of 2023. More than 70% of PBR’s oil is sold in Brazil. A significant depreciation of the real would increase PBR’s debt service costs. Lula’s latest oil export tax hike and interference in PBR pushed the Brazilian currency lower versus the U.S. dollar.

We do not view asset expropriation as a risk for PBR shareholders. We wouldn’t say the same for other Latin American national oil companies, such as Ecopetrol (EC) of Colombia. However, “windfall” profits taxes become a growing risk when oil and gas prices are high. We’d point out, however, that they’re also a risk in Europe and other regions viewed as less hostile toward capital than Latin America. The Irish and German governments levied windfall profits taxes on Vermillion Energy (VET:CA) in 2022 after its outsized earnings in response to high commodity prices. VET paid tax rates of 75% and 33% on windfall profits in those jurisdictions, respectively.

For Brazil, higher energy prices typically lead to higher inflation, which brings problems for the government. Persistent inflationary conditions may induce the Brazilian government to increase its take from PBR via increased royalties, increased income taxes, and/or increased special taxes. Higher inflation could also bring about refined-product price controls mandated by the government that force the company to sell its oil at a loss to domestic consumers, as it was forced to do in the years before 2013. Back then, reduced cash flow could cause the company to increase long-term debt to fund its capex. Today, a higher debt balance would lower PBR’s credit rating, increase its funding costs, and ultimately endanger dividends for the common shares.

PBR’s financial problems could be compounded if the Brazilian government forces the company to keep its payroll bloated so as not to exacerbate layoffs in a downturn. And if layoffs were to occur, large-scale strikes could reduce PBR’s earnings and damage relationships between management, labor, the government, and private investors.

Operational risks include the massive clean-up costs that would likely arise in the event of a blowout of an offshore well.

Despite the tons of ink spilled on PBR’s political risk and its consequences to PBR’s operations and finances, we view the company’s greatest risk to be long-term asset depletion. Whereas the market may be comfortable assuming PBR can indefinitely replace more than 100% of its annual production, we don’t expect that to remain the case. The next five years will be telling.

If it turns out that PBR’s reserve replacement ratio begins to fall, signaling the advent of long-term production decline, will the Brazilian government, as the controlling shareholder, become more activist in company affairs? Does it view the imminent risks as sufficiently severe to tilt the scales in its favor by penalizing outside private shareholders? We don’t know the answers to these questions, but as typically happens when an economic pie begins to shrink, conflict becomes more likely. We wouldn’t want to be in a position where we receive the short end of the stock.

Valuation & Commodity Price Sensitivity

We value PBR shares in the range of $20 to $25 without considering the risk to future cash flows.

Our discounted cash flow valuations estimate value per share at $75 per barrel Brent/$3.00 per mcf natural gas and $87.50 per barrel Brent/$3.50 per mcf natural gas, both using a 12% discount rate. We consider this to be a conservative long-term price range, and we use these prices as lower and upper bounds on our valuation range. Our valuation represents PBR’s total equity value per share, including all common and preferred shares outstanding.

The lower bound of the value range implies 34% upside from the current common stock price of $15.14.

At $80 per barrel Brent, we estimate PBR would have dividend capacity of $2.67 per share. If the company paid out all its free cash flow as dividends at that oil price, its dividend yield would be 17.6%. However, PBR is likely to retain cash flow for debt reduction and other purposes, so its actual dividend yield would likely remain in the 12% to 14% range, absent political interference.

PBR’s free cash flow breaks even at $45 per barrel Brent, assuming budgeted capex. If PBR operated in maintenance mode, its breakeven per barrel would fall below $30 Brent.

PBR has significant cash flow torque to higher commodity prices, particularly with the share price so depressed versus intrinsic value. At $100 per barrel Brent, the stock would trade at $30.13 per share, represeting nearly 100% upside. This valuation would come about assuming the shares traded at a 12% free cash flow yield and before consideration of risk to future cash flow.

Instead of changing our valuation to reflect the possibility that future cash flow is impaired by an adverse event, we would rather simply demand a larger margin of safety in our purchase price. Today’s $15 per share is verging on “not big enough” relative to the $20 per share lower bound of our valuation range. We would prefer to buy PBR shares in the $12.00-to-$13.00 range. At that price—assuming we continue to expect higher oil and gas prices over the long term—we would expect either price appreciation or a high forward dividend yield to offset much of the long-term financial risk in the share price. If history is any guide, perceived financial risk is likely to be greater than actual financial risk, so we could be eager buyers of the shares for long-term holding.

Our favored way to buy PBR stock would be to wait for some sort of fear to send the shares lower. It could be the fear of dividend restrictions or managerial turmoil. Or it could be a cyclical downturn that imperils the common dividend. Under such circumstances, we would wait for the spread between the common and preferred to narrow. When it does, we would consider buying the common shares. At that point, they would trade at a similar dividend yield—assuming the common dividend was safe—and they would offer more upside relative to the preferreds.

More conservative investors should stick to the preferreds. Their dividend will always be safer than the common shares and they are more likely to retain their value in a cyclical downturn.

Conclusion

The headlines surrounding PBR imply greater economic risk than actually exists in the shares. We expect the shares to continue to be as volatile as Brazil’s political atmosphere.

We would refrain from buying until fear creeps back into the share price, at which point we would be comfortable owning a 5% position in the shares, and perhaps slightly more if the price was low enough and total return prospects were sufficiently attractive.

PBR shares at their current price are an attractive alternative for income investors who seek E&P exposure. Unless oil prices fall below $70 per barrel, we expect their yield to remain above 10% inclusive of the 15% withholding tax that most U.S. citizens pay on Brazilian stocks.

PBR presents an attractive economic package. Investors should patiently wait for the price that suits their investment needs and risk tolerance and hold for the long term.

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

By: Jon Costello

The selloff in natural gas names has provided an opportunity to add to our income holdings. This morning, we published a trading alert that we bought 7,050 of Mach Natural Resources LP (MNR) units for the HFIR Energy Income Portfolio at $10.83 per unit. We plan to add to our position if the units fall further from here.

MNR Review & Update

Mach is an oil and natural gas E&P consolidator that acquires producing, cash-flowing acreage at a discount, operates it efficiently, and returns a large portion of cash flow to unitholders through distributions. It aims to grow its operations by purchasing assets below PDP PV-10 with a focus on increasing distribution capacity per unit.

The company’s strategy is focused on keeping leverage low. It targets net debt at less than 1.0-times Adjusted EBITDA. It aims to maintain a reinvestment rate below 50% of operating cash flow, reduce production decline rates, and keep operating costs low. Its strategy has effectively supported large and increasing unitholder distributions. Currently, its distribution is the highest among E&Ps.

Mach projects 2026 production of 151,000 boe/d, with a 71%/29% split between natural gas and liquids. Proved reserves total 653 million boe, of which 87% is PDP with a PV-10 value of $3.3 billion. Its reserves are summarized below.

Source: Mach Natural Resources December Investor Presentation.

Mach has an enterprise value of $2.9 billion with its units trading at $10.83. The discount to PDP calculated using commodity prices we believe are below mid-cycle levels, offers a significant margin of safety at the current unit price. Such a margin of safety is difficult to find among Mach’s North American E&P peers.

The margin of safety in Mach units, the temporary nature of the selloff, and the units’ upside potential make for an attractive opportunity. Long-term investors should consider buying the units below $12.00.

Why Mach Units are Undervalued

The first reason for Mach’s undervaluation is that MLPs remain out of favor. MLP units are heavily owned by individual investors who often lack the staying power of larger institutions that focus on C-corporations. Most MLPs are of the midstream variety, and these equities consistently trade at a discount to their C-corporation peers.

The MLP discount relative to C-corps is the biggest disadvantage for public companies that adopt the structure. However, this tends to be offset by the higher distributions paid by most MLPs.

Despite the equity price discount, longtime readers appreciate my fondness for midstream MLPs. The structure offers several advantages. For instance, MLP distributions are treated as a return of capital, so taxes are deferred and usually lower than those of C-corps. MLPs don’t pay corporate income tax, so they generally have more distributable cash flow than C-corps.

The MLP discount also creates opportunities for accretive unit repurchases. Mach hasn’t repurchased any units since its October 2023 reorganization, but it could make accretive repurchases if it chose to do so.

The downside of the MLP structure historically has been aggressive governance practices that favor the partnership’s sponsor over its common unitholders. This issue has been largely remedied in recent years through various governance reforms. Still, an investor in an MLP should be comfortable with the partnership’s management and board of directors, which exercise significant control over the limited partnership.

E&Ps MLPs are treated with added skepticism by investors because they’re seen as income vehicles but entail greater commodity price and depletion risk than midstream MLPs. However, Mach’s low-decline asset base, sensible acquisition program, and conservative operating and financial structure mitigate much of the risk.

A second factor holding down Mach’s unit price is low oil prices and a recent selloff in natural gas prices. We believe both are temporary. As such, we view the units’ weakness as a good opportunity to initiate a position. As commodity prices recover, Mach’s cash flow per unit will rise, leading to larger quarterly distributions and a higher unit price.

Third, Mach’s units are also out of favor due to the company’s policy of paying variable distributions, which fluctuate widely. For example, the distribution was $0.79 per unit in the first quarter of 2025 and fell to $0.29 per unit in the third quarter.

Source: Mach Natural Resources December Investor Presentation.

A variable distribution policy is the most intelligent approach for an E&P. We understand that the stock market craves regularity, but as long-term owners, we appreciate that Mach’s policy of paying variable distributions adds a layer of financial flexibility and safety that it wouldn’t have if it committed to paying a regular base distribution. The policy also reflects the fact that Mach is an E&P with highly variable cash flow driven by commodity prices and the need to allocate cash to fund acquisitions.

Fourth, Mach’s units are under pressure because the company’s leverage has increased to 1.3-times Adjusted EBITDA, surpassing the company’s long-term target of 1.0-times. The debt was used to finance the company’s recent transformative acquisitions in the Permian and San Juan basins. Reducing debt will likely take precedence over paying distributions, particularly at low commodity prices, where higher leverage presents greater risk. Unitholders are likely to see significantly lower distributions over the next few quarters, as cash flow available for distributions will decline if commodity prices stay low and free cash flow is allocated to debt reduction.

We aren’t concerned by any of these factors holding down the price of Mach units. They’re all either irrelevant to us as long-term equity owners or temporary in nature. The company is in good hands under its current leadership. Its significant insider ownership further strengthens our confidence. Insiders own 74% of the common units. Note that insiders purchased additional units on the open market in November and December of last year at prices ranging from $11.45 to $12.41.

We intend to hold the units for several years, which we believe is more than enough time to permit a substantial recovery in distributions and the unit price. The fact of the matter is that a lot of “bad” is priced into the units at their current price of $10.83. That price implies the market is overlooking the company’s advantages, its prospects for higher revenues and lower unit costs, and its conservative approach to managing its business. Given the current setup, I suspect any good news on a company or macro level is likely to send the units higher.

Positive Operating Results

Mach is succeeding in its goal of maintaining low operating costs. The company is integrating its recently completed acquisitions and expects its lease operating costs to be approximately $6.90, roughly in line with its pre-acquisition level.

The company was able to cut drilling and completion capital by 18% in its 2026 capital program while maintaining production guidance. The freed-up cash flow from lower capex can be used to pay down debt.

Typically, the stock market would reward such an achievement with a higher stock price, but Mach’s status as an MLP limits analyst and investor coverage, so news can slip through the cracks.

Drilling results have been impressive, demonstrating the quality of Mach’s acreage. The company drilled a two-well pad in the Deep Anadarko that produced over 40 MMcf/d, while the first five wells drilled in the Mancos shale delivered more than 100 MMcf/d of low-decline production. These results illustrate that management can selectively allocate capital into high-return projects when commodity prices justify the investment.

The recent acquisitions will further lower Mach’s production base decline rate. A low decline is a key feature for an E&P income vehicle. For example, one of my favorite Canadian oil-weighted names, Cardinal Energy (CJ:CA), has successfully maintained its large dividend in large part due to its low decline rate. The low decline rate decreases maintenance capital, supports cash flow distribution, and makes Mach’s pledge to reinvest less than 50% of its cash flow more credible.

The company remained true to its pledge to reinvest less than 50% of its cash flow. In the nine months ending September 30, 2025, Mach generated $361.3 million in adjusted operating cash flow and invested $165.6 million in capex, representing a reinvestment rate of 46.5%. Free cash flow was $195.8 million, and unitholder distributions amounted to $197.7 million.

Mach’s recent pivot toward natural gas is another strong point of its operation. We’ve seen other income vehicles among our holdings, such as Black Stone Minerals (BSM), make similar pivots toward natural gas to good effect. If gas fundamentals tighten later this year with the ramp of North American LNG production, the company will be favorably positioned to benefit from higher domestic natural gas prices. Data center growth provides another demand driver for natural gas.

Longer-term, even if gas prices struggle to stay above $5.00 per mcf due to an abundance of supply, all the new demand indicates the market is unlikely to experience a repeat of the 2023-2024 downturn. I suspect painful memories of that incident exacerbate the selling of natural gas-weighted equities like Mach amid significant declines in gas prices.

Valuation

Mach’s value ultimately depends on the course of oil and natural gas prices. We’re confident that oil and gas prices will trade at significantly higher average prices over the next few years. Higher commodity prices will lead to increased distributions from Mach, as well as a higher unit price. This outlook makes the units’ prospective total returns particularly attractive at their current price of $10.83.

Mach units are cheap based on virtually any metric.

• Enterprise value of $2.9 billion trades at a discount from proved reserve PV-10 of $3.3 billion.

• PV-10 is likely to grow as the company continues its successful track record of making accretive acquisitions.

• EV/Adjusted EBITDA is roughly 3.8-times.

• Mach’s enhanced decline rate, integration synergies, and midstream optimization measures taken after its recent acquisitions will increase cash flow and reserve upside.

• Adjusted EBITDA and operating cash flow stand to grow as operating costs per unit decline and commodity prices rise.

• Leverage will fall as Adjusted EBITDA increases and debt is paid down.

• Distributable cash flow per unit was higher than it appeared at the end of the third quarter due to Mach’s recent acquisitions. The 49.8 million additional units issued in the deal increased the unit count by 42%, but because the deal closed on September 16, Mach had only two weeks of revenue contribution from the new assets. Future quarters will offer a clearer view of the company’s cash-generating capacity.

Mach still generates free cash flow at current commodity prices. Using the midpoint of the company’s latest guidance, I estimate free cash flow excluding hedges at $60 per barrel WTI and $3.50 per mcf Henry Hub of approximately $140 million, equivalent to a 10.4% free cash flow yield. Hedges boost that figure modestly. This yield is on par with large midstream MLPs.

At current commodity prices of $57.00 per barrel WTI and $3.41 per mcf Henry Hub, I estimate that Mach units trade at a 7.9% free cash flow yield on an unhedged basis.

Mach unitholders should expect distributions over the next few quarters to decrease from previous quarters. Capex will consume the lion’s share of cash flow, and a significant portion of the remaining free cash flow will be used to reduce debt. Although EBITDA fluctuates with commodity prices, I assume Mach will aim to pay down roughly $250 million in long-term debt to reduce its leverage ratio to its long-term target. While there isn’t urgency to reduce debt, Mach has been run with an emphasis on conservatism and has closely adhered to its foundational operating principles, one of which is to keep Adjusted EBITDA of 1.0-times net debt. I therefore expect it to allocate half of the cash flow to deleveraging, and perhaps more.

The lower distribution could lead to further weakness in the unit price. We are prepared to buy more units if that happens. However, such potential near-term downside—which is by no means certain—is more than offset by the tremendous long-term upside offered by the units at higher commodity prices. This cash flow torque to higher oil and gas prices is why Mach represents a superior investment alternative for long-term income-seeking accounts relative to other MLPs and even most midstream operators at their current prices.

From the current $10.83 unit price, Mach units offer a potential double if WTI trades at $85 per barrel and Henry Hub natural gas trades at $4.00 per mcf. These oil and natural gas prices are in the ballpark with our average price expectations over the coming years as natural gas demand grows globally and non-OPEC crude oil production approaches full capacity after 2027. Of course, returns to Mach unitholders increase significantly as commodity prices increase, as illustrated by the table below.

Risks

The one material negative in Mach’s financial picture over the first three quarters of 2025 was its $90.8 million asset impairment, largely attributable to lower oil prices. However, if oil and natural gas prices are higher than those that prevailed in 2025—as we expect—then the value of the impaired assets should increase substantially relative to the value ascribed under full-cost ceiling accounting. Still, additional asset impairments could pose a risk to unitholders.

The units face other risks. For example, Mach units might trade lower for longer than I expect if a natural gas glut emerges, possibly caused by LNG oversupply. This risk is reduced in 2026 by the company’s hedges, which cover approximately half its expected production for the year. Additionally, I don’t expect a domestic gas glut to be a risk until after 2027, at which point we expect oil prices to be much higher.

Furthermore, all E&Ps share commodity price risk, and Mach’s low-decline asset base and conservative balance sheet position it well relative to peers. Still, sustained low commodity prices could hinder the company’s ability to finance the asset acquisitions needed to extend its reserve life and runway of generating distributable cash flow.

Another risk for Mach unitholders is that the company’s financial prospects depend on management’s discipline. If that discipline wilts, so will the unit price. For instance, if Mach were to acquire assets with meaningfully higher decline rates, or if it fails to realize operational efficiencies from acquired acreage, returns for unitholders could be lower than I expect.

Like all E&Ps, Mach’s assets deplete over time, so extending reserves will be an important part of extending unitholder value and supporting the unit price. If Mach cannot find attractive acquisitions, it may be tempted to acquire less attractive alternatives, which would lower its return prospects.

Also, discipline imposed by leverage could act as a constraint on growth, or even distributions, in a severe bearish scenario. Restrictive covenants and debt agreements can limit distributions if commodity prices fall and borrowing bases tighten.

Despite these risks, we expect Mach to stay disciplined. The company’s leadership is heavily incentivized to act in the best interests of all common unitholders.

Conclusion

Mach’s model of buying PDP at a discount, maintaining a low decline rate, and returning cash flow to unitholders is sound, but faces pressure from low commodity prices and its intention to use cash flow for debt reduction rather than distributions. However, we believe this pressure is temporary. As such, it presents an attractive buying opportunity for long-term investors. Those who believe commodity prices will rise from current levels and who are confident in Mach’s management team, as we are, can secure a bargain price today.

We consider the near-term prospect of lower distributions to be an inconvenience, not an existential risk. After all, the units already discount lower distributions under any reasonable view of mid-cycle commodity prices. We expect higher commodity prices and Mach’s increasing operational scale to drive the units higher over time and make the current valuation look cheap in hindsight.

Analyst’s Disclosure: I/we have a beneficial long position in the shares of MNR in the HFIR Natural Gas Portfolio and HFIR Energy Income Portfolio, CJ:CA, BSM either through stock ownership, options, or other derivatives.

But the reality underneath is different. The adjustment factor was reported at -394k b/d, suggesting that the real US crude oil production figure was 13.476 million b/d (13.87 - 0.394).

Source: EIA

Now, it’s important to keep in mind that the US government shutdown impacted US crude export data. Using our physical tanker movement and adjusting for the difference, the trued-up adjustment was -294k b/d (100k b/d lower). As a result, the “real” US crude oil production figure was 13.576 million b/d.

In October 2024, the same methodology produced a “real” US crude oil production figure of 13.312 million b/d. The increase y-o-y is +264k b/d.

At HFIR, we track US crude oil production in real-time, and this is how we did:

Our estimate for October was 13.542 million b/d vs 13.576 million b/d.

Looking ahead, US crude oil production is expected to rebound in November and December. Our real-time production tracker shows 13.85 and 13.768 million b/d, respectively.

Our real-time US crude oil production tracker suggests that overall production peaked in September, and we should expect to see further weakness ahead. We assume that with WTI where it is today ($58), US crude oil production will decline back to ~13.3 million b/d by the middle of 2026.

Now, the interesting datapoint you can see in our composite index is the strength we are seeing in associated gas production. This was a clear trend throughout 2024 to 2025, and we suspect a higher gas-to-oil ratio will continue to contribute to this widening trend.

From a supply & demand standpoint, the weakness in implied US crude oil production is a good sign, but not enough (at the moment) to dramatically change the calculus.

The consensus is still expecting global oil inventories to build in Q1, so any meaningful uptick in oil will be muted with this fundamental backdrop. The decline in US crude oil production won’t meaningfully impact global oil balances until H2 2026, and if global oil demand remains healthy, we should see the oil market tip into a small deficit.

Analyst’s Disclosure: I/we have no stock, option or similar derivative position in any of the companies mentioned, and no plans to initiate any such positions within the next 72 hours.

President Trump launched a successful operation in Venezuela and captured the Venezuelan President, Nicolás Maduro. We won’t go into the geopolitical reasons for the US actions or any other geopolitical factors; we will leave that to experts like Dr. Anas Alhajji.

Instead, we will focus this piece on these impacts:

• Oil price impact.

• Dynamics of sanctioned barrels and unsanctioned barrels, and how that impacts supply & demand.

• Implications on long-term global oil market fundamentals.

• Equities that could benefit.

Implications on Oil Price

In normal market environments, a regime change in an oil-producing country would be immediately bullish for the oil market as traders assume 100% disruptions to crude export flows.

In this case, oil exports out of Venezuela do not constitute “normal”.

Venezuela only exports ~800k b/d, with almost the entirety of the exports going to China via dark fleets.

Source: Dr. Anas Alhajji

The reason why this is so important to understand is that China is the “only buyer” of “sanctioned” barrels. When you think of sanctioned barrels, these are oil exports from Russia, Iran, and Venezuela. Sanctioned barrels operate under a different physical pricing dynamic than unsanctioned barrels.

In this particular case, given that China is the only buyer of sanctioned barrels, it enjoys a healthy discount to the spot price. China can exert its enormous buying power and demand large discounts for the crude. This, indirectly, hurts unsanctioned barrels as it reduces demand from China on outside barrels, and thus, pressures oil prices.

Now that Maduro is out and China will no longer be able to take advantage of “cheap” crude from Venezuela, this ~800k b/d will open up to the unsanctioned segment of the oil market. In other words, oil traders will assume that Venezuelan crude exports will be made available to the rest of the world, and they will compete like-for-like with other heavy oil exporters, such as Mexico and Canada.

Keep in mind that the dynamics we are describing here assume no meaningful disruption to Venezuela’s crude exports.

All things equal, the sudden availability of Venezuelan crude to the unsanctioned segment of the oil market is net bearish. From a fundamental standpoint, the unsanctioned segment of the oil market would desire the heavy crude that Venezuela exports, especially to US refineries.

US commercial crude storage is already near multi-year lows, and with the recent drop in refinery margins, the availability of heavy crude will be a net positive for US Gulf Coast refineries.

As a result, our view on the oil price impact in the near-term is that it’s a net-negative. We see a small downward move in price ($2/bbl).

Supply & Demand (2026)

The unsanctioned segment of the oil market will need the crude available from Venezuela. China, which has enjoyed the discretion of being the sole buyer of Venezuelan crude for a very long time, will need to start stockpiling other sources of crude if it intends to fill up the SPR this year.

The increased buying from other sources may result in a more medium-term bullish impact on oil. While the market’s initial reaction is to assume that it’s bearish and the unsanctioned segment of the oil market will now have to compete with Venezuelan crude oil, the eventual increased buying from China will help prop prices back higher.

From a supply & demand standpoint, Venezuela’s oil production of ~1 million b/d will not see any meaningful increase anytime soon. Oil infrastructure in Venezuela is so deteriorated to the point that any meaningful increase in production will take billions and years of capex.

We estimate that if US oil majors express interest and commit to investing in Venezuela, it would take 2-3 years to increase production by ~500k b/d. There is still a lot of uncertainty on the ground, and no one knows what the transition would look like or whether there’s chaos during the transition. So please take that 2-3 years with a grain of salt.

Once there’s more clarity on the political transition and assuming no more chaos, and only if oil majors in the US commit, then the time clock begins. Venezuela has a lot of low hanging fruits that will see production bump up quickly, but to have a sizable and sustainable ramp, that would take 5+ years (at minimum).

For our global oil supply & demand model, I think it’s safe to assume that Venezuela’s oil production will remain around ~1 million b/d for this year. Even if we see a sizable commitment from the majors, oil production would not meaningfully increase this year.

So if you are wondering how this Venezuela news impacts global supply & demand this year, the answer is: nothing.

Long-Term Supply & Demand Model

There is still a lot of uncertainty as to what the “new” Venezuela would look like, but if we assume a US-friendly regime and one that’s pro-oil, then there’s a plausible scenario where Venezuela could reach ~2 million b/d by 2032-2033.

The technical background will be complicated to meaningfully increase production. First, the oil infrastructure in Venezuela was in terminal decline since the early 2000s.

From industry experts we’ve spoken to in the past, Venezuela’s oil sector would require a complete overhaul of all the equipment to sustain production anywhere near ~2 million b/d. You might temporarily get production higher, but to sustain that level, you would need billions of capex.

Oil majors will not make such a commitment and investment unless they are certain that 1) the regime change is safe and 2) there are legal processes in place that can support legal ownership.

Even if all the frameworks are in place, it would take time before they can convince conservative boards to aggressively pursue the Venezuela option. The only mechanism that we think could expedite this is if the US government throws its weight behind guaranteeing the contracts. Outside of that, oil majors will wait.

In our view, the earliest Venezuela will impact global oil balances won’t be until 2028 to 2029, and for it to increase by ~1 million b/d, we would have to wait until 2031 to 2032.

Because of this dynamic, the Venezuela situation does not meaningfully change the future global oil market balance.

Equities

There are very limited direct beneficiaries of this. Sanctions imposed on Venezuela led many oil companies to avoid Venezuela altogether. In this case, Chevron is the only oil major still operating in Venezuela thanks to a special license granted by the US government.

From an operational standpoint, because of Chevron’s continued involvement there, it would be the first oil major to truly understand the political transition. It would also have a board that would be supportive of an aggressive move in Venezuela. It would not surprise me if Venezuela could, eventually, add ~350-400k b/d for Chevron. This is a clear positive for Chevron.

Another equity name that would benefit is New Stratus Energy (NSE.V). NSE previously had ownership in a Venezuelan joint venture with Goldpillar. The company announced at the end of 2024 to exit following Trump’s presidential victory. In fear of sanction risks and increased geopolitical turmoil, NSE took a loss, but kept an arrangement in place to buy the stake back in the event of any meaningful political change. We reached out to the company, and the President informed us that it can buy it back for $1.

Background of the JV: The joint venture asset produced ~1,300 boe/d (at the time of the exit) with a historical capacity of ~60,000 boe/d. Here’s the press release when it was first announced.

Other oil companies that would benefit from this include:

• Schlumberger (SLB), Halliburton (HAL), Weatherford (WFRD), Baker Hughes (BKR): To increase Venezuela’s production capacity, oil majors will need to spend billions on capex and service providers. Oilfield servicing stocks would benefit.

• Exxon and ConocoPhillips: These two oil majors had history with Venezuela in the past and are very familiar with the assets. While the board will be highly skeptical due to past disputes, if the geopolitical climate is more certain, we see both oil majors re-entering the fold.

Conclusion

In summary, the initial market reaction might be bearish as oil traders will assume that the sanctioned barrels will now compete with the unsanctioned barrels. But in the medium-term, China will look to replace the lost crude from Venezuela, so the buying (in the unsanctioned segment of the oil market) will be a net-positive for oil prices. And in the long-run, the impact of the regime change is negligible on global oil market balances. Venezuela is already producing ~1 million b/d, and production won’t increase to 2 million b/d until 6-7 years from today.

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

For the week ending Dec 19, we have a crude draw of 2.87 million bbls. This is in line with the 5-year average draw of ~2.9 million bbls.

This crude draw coupled with our preliminary forecast for next week will push US commercial crude storage near multi-year lows. This is in sharp contrast to our earlier forecast for a range of ~440 to ~460 million bbls.

The main variables that contributed to this are:

• Higher-than-expected refinery throughput.

• Lower-than-expected crude imports.

The low crude imports were surprising considering how elevated global oil-on-water is, but as we noted in our other OMFs, the surplus is entirely from Russia and Iran, so the unsanctioned crude side remains “tight”.

On the production side, if EIA confirms the small crude draw, US crude oil production will average close to ~13.6 million b/d for December.

Following the brief ramp-up we saw in August to November, we think US crude oil production is set to fall going into 2026.

On the product side, readers should expect material builds. For end-of-year tax reasons, refineries typically stockpile product and keep crude storage low. API reported only +1.1 million bbls for gasoline and +0.7 million bbls for distillate.

If EIA confirms the small builds, product storage will be in line with previous averages.

Finally, the US total liquids stockpile is where you will see the bulk of the surplus in the oil market balance:

Now compare that with the big 4 inventory balance (crude, distillate, jet fuel, and gasoline):

And you can quickly see that the surplus the market is pointing to is largely in NGLs and other liquids. Note: At least from the US oil inventory perspective.

In aggregate, US commercial crude storage is expected to finish near the multi-year lows despite the consensus estimates calling for a massive surplus in Q4 2025. This is one of the few times in the oil market history where the surplus elsewhere did not translate to visible US inventory builds, yet.

API vs EIA

Following API’s crazy -9+ million bbl crude draw figure last week (EIA reported -1.274 million bbls), API vs EIA running error has blown out to +29 million bbls. As a result, API’s crude storage estimate (+2.4 million bbls) is expected to be more bearish than EIA.

By our estimate, EIA should report near -2.5 to -3 million bbls or in line with our estimate.

Sable Offshore should be nominated the “drama stock of 2025” for the never-ending entertaining twists and turns this name provides. For both bulls and bears, the good news is that the name won’t exist much longer given the precarious cash situation the company is in, despite raising $225 million net in its latest capital raise.

In this article, we will explain to you the following:

• The pipeline route is like dead, really dead.

• The OS&T (offshore) route is unrealistic, impractical, and impossible to achieve within the timeframe the company is proposing.

• The available support options from the Federal government are extremely limited, and extremely unlikely to materialize.

• After we walk you through all of this, you will see why we think it will be impossible for Sable to raise additional financing.

Pipeline is Dead

Sable’s pipeline route is dead. In order for the pipeline to restart, the following events will need to take place.

• Sable would need to win the court case in Kern County. The company is forcing the court to specify whether or not SB 237 (CDP for restart) applies to Sable’s pipeline. Sable’s argument in this case contends that the Pipeline and Hazardous Materials Safety Administration (PHMSA) only defines active and abandoned. There is no definition for “idle,” and as a result, Sable’s pipeline has been active this entire time and was never idled. If Sable does not win this, then the SB 237 deadline of Jan 1, 2026 kicks in, which will force the company to get a coastal development permit.

• Sable would need to appeal Judge Anderle’s ruling on Oct 15, 2025, where he denied the writ. The CCC currently has a cease and desist (CDO) order, a restoration order (RO), and an $18 million fine. Sable would have to win the appeal.

• Santa Barbara County denied the Exxon permit transfer on November 4, 2025. Even if Sable wins both the Kern County (SB 237) case and Anderle’s CCC case, it would still need SB approval for the permit transfer. If not, SB can issue a cease and desist order on the Las Flores facility.

• If Sable, somehow, wins the SB 237 case, the Anderle CCC case, and the SB county permit approval, it would still need to do all of the anomaly repairs in the coastal sections. After which, Sable would need to resubmit the final restart plan to California’s State Fire Marshal (OSFM). The OSFM would have to approve the pipeline for restart.

• After all this is said and done, Sable would have to submit the restart plan to Judge Geck, where it would need to survive 10 court days.

If any of the routes above fail, the pipeline route dies. And even if it wins the SB 237 and CCC case in the appeals court, they will be tied up in litigation. The counterparties would sue again, and court delays will guarantee that none of this would start before January 1, 2026.

Pipeline Hail Mary

In Sable’s latest 8-K filing, it notified the Pipeline and Hazardous Materials Safety Administration (PHMSA) that the “pipeline connecting the Santa Ynez Unit to the Pentland Station terminal in Kern County, CA constitutes an interstate pipeline facility under the Pipeline Safety Act.”

Just in case readers are not fully aware of this, following the Refugio oil spill in 2015, the consent decree signed by PHMSA transferred oversight to the California Office State Fire Marshal.

Consent Decree

3MB ∙ PDF file

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Could PHMSA change the designation from intrastate to interstate?

Sure, but good luck getting that through court. The consent decree would make it nearly impossible 1) for PHMSA to change it back and 2) for any court to accept the change.

As a result, this is a dead-on-arrival strategy.

Offshore Route Is Bad

In order to successfully pivot the company to the offshore storage and treating vessel (OS&T) route, we estimate that Sable would need the following:

• $3 to $3.7 billion of financing.

• 48 months.

NEPA

Before we start discussing the permits needed, it’s important to understand that the Santa Barbara County air permit (one of the many items) is a key gating mechanism. As a result, the only way the company can avoid having the air permit issue is if it parks the OS&T 25 nautical miles outside of the coastal zone. This will trigger the National Environmental Policy Act (NEPA).

The Department of Energy (DOE) requires NEPA to give a federal loan guarantee, and the Bureau of Ocean Energy Management (BOEM) will require NEPA for the permit.

Under President Trump, the expedited NEPA process could take 30 days, but such a process would likely be challenged in court. Realistically, the NEPA process could take up to 12 months, assuming legal challenges pile up.

BOEM Permit

On the leaked investor call, Jim Flores, CEO of Sable Offshore, alleged that the “permit” will come before Thanksgiving. Now that it’s Dec 1, it was obvious that it was logistically impossible to have a BOEM permit in place.

On Oct 9, 2025, Sable issued an 8-K noting that it “updated” its Development and Production Plan for the Santa Ynez Unit (DPP). The company said that it believes the existing permit is still “active”.

The statement is factually inaccurate.

In recent sellside commentary, Sable’s management team has been telling analysts that the Commerce Department can override the 1984 deferred CZMA override decision. Below is the file from 1984 on why the Commerce Department deferred/rejected the override.

Czma Rejection 1984

3.83MB ∙ PDF file

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This time around, Sable appears confident that Howard Lutnick, Commerce Secretary, will be able to override a decision deferred from 41 years ago. Never mind the fact that the existing 1982 permit is completely out of date and inadequate for the production guidance the company is touting (60k boe/d production).

Don’t believe me? Look at the transcript of the Monday public conference call following the Hunterbrook article:

Transcript

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To make matters worse, if you go through the 1984 rejection, it specifically notes that if the onshore route isn’t available, the Commerce Department would revisit. In 1985, the CCC allowed the onshore pipeline through, and Exxon eventually abandoned the OS&T.

So to think that the Commerce Department would override something that has already taken place and to do it on the old 1982 permit is just hilarious and ridiculous.

What’s a viable path?

Outside of the fantasy scenario the company is touting to sell-side analysts, there’s a valid way Sable can obtain a BOEM permit. For Sable to successfully pivot to the OS&T route, it would need to park the OS&T 25 miles outside of the coast. The reason this is important to understand is that the Santa Barbara County will issue the needed air permit, and the only way to bypass this is by doing the above strategy.

But this strategy brings other issues.

1. The hefty cost associated with the buildout.

2. The timeline it takes for the buildout to take place.

3. It’s no longer a minor update on the existing permit, but a complete overhaul.

As a result, BOEM’s review process will take time as it will require the following:

• Air permit (EPA OCS above 25 nautical miles): This will also trigger its own CZMA review (6 months, below for more info). It will require the Commerce Secretary's override.

• NEPA (above).

• National Pollutant Discharge Elimination System (NPDES) authorization.

• Oil Spill Financial Responsibility (OSFR) and Certificate of Financial Responsibility (COFR).

• Oil Spill Response Plan (OSRP), Vessel Response Plan (VRP), and Facility Response Plan (FRP).

• BSEE safety systems approval (Subpart H), pipeline approvals (Subpart J), and construction/installation notices.

• Coastal Zone Management Act (CZMA): This gives a coastal state a binding say (federal consistency) over federal actions. The California Coastal Commission (CCC) is the state reviewer. The CZMA process takes 6 months, and given Sable’s history with the CCC, they will likely reject the plan. This is the part that will be sent to the Commerce Secretary, where the company thinks Howard Lutnick will override on the premise of “national security.”

BOEM Permit Timeline - 12-18 months, minimum.

Construction to Production Start (24 months, minimum)

Let’s assume that Sable is successful thus far and receives the BOEM permit after many legal battles with the environmental groups. The BOEM permit in hand took 12-18 months following all of the above requirements. This is when Sable will (if) receive federal funding support to START the buildout of the OS&T and the subsea tie-back needed to connect the offshore platforms to the OS&T.

Reasoning why it needs the permit? The company cannot risk spending on OS&T (at the risk of not obtaining the permit), and it cannot legally start work on the subsea tie-back until the permit is in hand.

The OS&T buildout alone will take 18-24 months.

The subsea tie-back will take 12-18 months.

In conclusion, there’s no scenario Sable will be able to sell oil by Q4 2026. At a minimum, we won’t see any oil sales until late 2029.

Federal Support, But How?

• Without a BOEM permit, Sable cannot obtain a Federal financing guarantee.

• Without NEPA, it can’t get equity or financing assistance from the Department of War (Department of Defense).

• Sable is asking the Department of the Interior for an “expedited” permit, but the only thing that can be expedited is NEPA. There’s no other mechanism that the DOI can expedite. It cannot expedite the air permit. It cannot expedite the CZMA. As a result, DOI is extremely limited.

• The Commerce Department can give an override on the CZMA under the pretense of National Security, but Sable would need to first go through a CZMA, which takes 6 months!

The only support Sable can receive from the Feds is verbal, but that’s about it. Can President Trump tweet about Sable and help it? Sure, but what’s in it for him?

Increase US crude oil production by ~40k boe/d by the end of 2029, when US crude oil production is already at an all-time high of 13.844 million boe/d?

Realistically, nothing. This is not an easy win for Trump.

As a result, Federal support is not coming.

Sable Is Out Of Money

At the end of Q3, Sable had $41.6 million in cash and cash equivalents with ~$53 million in accounts payable. In November, Sable managed to issue 45.45 million shares at $5.5 for gross proceeds of $250 million, $225 million net.

In the table below, we break down our assumptions for Sable’s cash balance by the end of December 2025:

Burn Rate

In our model, we assume an operating and maintenance expense of $50 million per month. This is the cash burn this year so far:

• Q1 2025: -$136.3 million, $45.4 million/month

• Q2 2025: -$265.2 million, $88.4 million/month

• Q3 2025: -$177.4 million, $59.1 million/month

In Sable’s latest Q3 filing, it notes the following:

Operations and maintenance expenses are expected to remain elevated for the remainder of 2025.

As a result, we think our assumption of $50 million per month is on the conservative side.

Exxon - $28 million legal payment and $25 million in restricted cash

In addition to the disclosure about elevated operations and maintenance expenses, Sable also disclosed the following in its latest quarterly earnings:

1. On October 14, 2025, the Company entered into the Fifth Amendment to the Sable-EM Purchase Agreement, pursuant to which the Company agreed to purchase a performance bond in the amount of $350.0 million in favor of EM as the sole beneficiary as plug and abandonment financial security, which is due three days prior to the Senior Secured Term Loan maturity (see further discussion of maturity date and Second Debt Amendment at Note 6 — Debt). In accordance with the Sable-EM Purchase Agreement, EM has the ability to request a performance bond increase to $500.0 million in favor of EM.

2. On October 14, 2025, the Company entered into a Letter Agreement Regarding Restart Production (the “Letter Agreement”) and the County of Santa Barbara’s Field Development Plan, with an effective date of June 1, 2025, whereby the Company agreed to provide EM additional consideration for lack of operatorship transfer. The Company will reimburse EM for costs associated with the Sable Offshore et al. v. County of Santa Barbara et al. litigation regarding operator permit transfer, and will compensate EM $4.0 million per month during the term of the agreement for operator related services. The term concludes at the earlier of (i) the completion of the transfer of operator or (ii) termination of the agreement by EM. Refer to Note 8 — Commitments and Contingencies for details regarding this County Permit Transfer Matter.

On item 1, the performance bond won’t be due until three days prior to the loan maturity. This will not be a cash drag item, but it will impose additional financing requirements if Sable is able to restart through the OS&T route.

On item 2, Sable agreed to compensate Exxon $4 million per month with an effective date of June 1, 2025. By the end of November, Sable will have needed to pay $24 million to Exxon and an additional $4 million in December. Since this agreement was made on October 14, it did not need to be disclosed in the financial statements. But this is a real cash expense, and by the end of December, Sable needs to pay Exxon $28 million.

Lastly, the new amended credit agreement requires Sable to hold $25 million in restricted cash. This needs to be subtracted from the cash balance.

CCC Fine

Judge Anderle has already ruled against Sable on October 15. The final clean-up is on Dec 3 where the CCC will ask Judge Anderle to dismiss the case. Sable, on the other hand, is asking Judge Anderle to make a ruling on discovery. Given Anderle’s ruling on Oct 15, it is extremely unlikely he will rule in favor of Sable.

According to the CCC fine of $18 million, Sable was supposed to pay that in early October. Given the ongoing legal case, CCC has not enforced the fine just yet. After Dec 3, it will likely enforce it. If Sable does not pay, CCC can put a lien on the assets.

Negative Cash Balance

By the end of December, Sable’s cash and cash equivalents will be negative. The company could prolong its death a few weeks, but the accounts payable will stack up, and another $4 million to Exxon will be due in January. Meanwhile, Sable’s legal bills are stacking up, and even using Sable’s $25 million per month burn rate to start 2026, it won’t have enough money to survive January.

Without another round of dilution, Sable will not even survive to see its Hail Mary attempts in the Federal government payoff.

Death Spiral 2.0

Following the Hunterbrook article, Sable’s stock price immediately went into a death spiral. The leaked audio call suggested that Sable needed to raise additional financing in Q4 prior to getting Federal support. Just the thought of an additional capital raise sent investors into a panic, and the stock spiraled down from $12 to $5 per share. Now that the company has raised $225 million to satisfy the Exxon loan extension requirement, many investors are not fully aware of just how dire the cash situation is.

In fact, we are speculating here that many of the PIPE investors were not fully aware of how dire the cash situation was. Dec 3 is the last date Sable said it would register the PIPE shares. Once those become registered, investors who felt that they were lied to on the deal will look to exit in a hurry creating the Death Spiral 2.0.

With no Federal Support on the horizon and no viable path to restarting oil sales via pipeline, the company will effectively run out of cash by January. Once the equity market realizes that, the reflexive feedback loop will feed on itself making it impossible to raise equity.

Conclusion

Sable Offshore will run out of money by January. Whatever tactic the company tries to throw at the market today will fall short because the reality is what it is. Any avenues for Federal support require the bare minimum, NEPA and BOEM permits, both of which the company does not have.

Some of the more audacious tactics like asking the Commerce Department to override a 1984 rejection are just borderline laughable.

Whatever the case, we explained our logic in this article:

1. Why the pipeline can’t restart.

2. The OS&T strategy will take 4 years and $3+ billion.

3. No imminent Federal Support is coming.

4. Why Sable will run out of cash by January.

All of this leads to one inevitable outcome: the equity becomes worthless.

Analyst’s Disclosure: We are long SOC puts.

On September 5, we published our OMF piece titled, “US Crude Oil Production Hits An All-Time High And What To Expect Going Forward.” At the time, we went against the consensus and noted that US crude oil production was meaningfully surprising to the upside.

This is the first time since we started tracking real-time US crude oil production that the data is showing +14 million b/d on a 4-week moving average basis.

Now, keep in mind that out of the ~14 million b/d, at least ~300k b/d of that will be condensate. However, even if we take that out, US crude oil production is averaging ~13.7 to ~13.75 million b/d in August.

What’s really strange/interesting about the data is that you can see the material weakness (below chart) at the start of the year going into May 2025.

But this all changed in June. Following the price spike resulting from the Iran/Israel conflict, US crude oil production jumped from ~13 million b/d to ~13.7 to 13.75 million b/d (14 million b/d if you include condensate).

Here’s what we wrote:Fast-forwarding to last week, the EIA confirmed the production uptick we saw in August via the EIA 914 report. US crude oil production came in at ~13.794 million b/d or +430k b/d y-o-y. And according to our tracker, September US crude oil production will be higher than August, but it will be the peak.

For readers following our US crude oil production closely, it may feel like the data is noisy, but I can assure you that the surprise to the upside is real (validated by EIA 914) and the current surprise to the downside is equally real.

What does this mean for the oil market?

Intuitively, it was difficult to make the argument that US crude oil production would sustain near ~14 million b/d at today’s oil price. Oil producer CEOs I’ve discussed with in the past few months were in complete disbelief of the data, but following the EIA 914 report last week, some acknowledged that the increase did take place.

In addition, we saw in Exxon’s Q3 earnings report that Permian oil production increased by ~100k b/d quarter-over-quarter and +300k b/d y-o-y. Exxon has been the primary driver of production growth, and the drop we are seeing now is likely a combination of the drop-off in activity we started to see in Q2 2025 and the price decline we saw in October.

From what we know for certain, the Iran/Israel conflict in June allowed US shale producers to hedge production in the mid-$60s and to save their capex program for 2025. But with WTI back down to $60/bbl and the forward curve averaging ~$62/bbl, there’s no room to increase production.

Going forward, US shale producer capex programs for 2026 will be slashed relative to the 2025 program. Our rough estimate is ~15% reduction with very minimal declines in production. Public Permian producers have the ability to keep production flat with WTI at $60/bbl, while private producers will account for the bulk of the decrease.

Our real-time data suggests a massive reversal in implied US crude oil production with the October average back to ~13.5 million b/d. My estimate for November is around ~13.4 million b/d, which is excellent news for those looking at 2026 balances.

But again, it’s important to caveat here that production would still be higher y-o-y despite the massive reversal we are seeing now. The oil market is far from being out of the woods as we need to see bullish data continue into November.

On the US commercial crude storage front, the drop in implied US crude oil production has dropped our estimate down to ~437 million bbls by year-end.

This would be in line with the 5-year average and higher than where we ended 2024.

On the global oil inventory side, the implied balance is very interesting. An oil trader we frequently talked to shared with us his implied balance data:

• Global observable liquids excluding China, SPR, and oil-on-water: +0.2 million b/d in Q4 2025.

• Oil-in-transit: +3.6 million b/d.

• China: -0.3 million b/d.

The bulk of the surplus is on the way to hitting onshore storage soon and this is why I think crude timespreads are starting to meaningfully weaken:

Brent 1-2

WTI 1-2

It’s very clear that the oil market is headed for contango, and when that occurs, you will see visible oil inventories pile up.

I think the US will be the last place that starts to build, so it will be a race against time. Can US crude oil production fall fast enough to keep up with the onslaught of crude that’s coming?

At this moment, I don’t think so.

Good Sign, Carry On

Let’s just say that I’m relieved. If US crude oil production really stayed at ~14 million b/d despite $60/bbl WTI, we would have been in an oil bear market for a long time. But real-time data pegged this week’s production at ~13 million b/d. There’s some data volatility involved here, but the good news is that the increase did not hold. As a result, we will need to see where US crude oil production bottoms out at and whether or not oil prices need to go lower to force even lower production.

And while what we are saying here is a “good sign”, it does not meaningfully change the fact that Q1 2026 will be oversupplied and that there’s a ton of crude on water today. Both factors will continue to pressure oil prices lower.

Analyst’s Disclosure: I/we have no stock, option or similar derivative position in any of the companies mentioned, and no plans to initiate any such positions within the next 72 hours.