By: Jon Costello

Last week, I made the case that fee-based midstream master limited partnerships (MLPs) are the income trade for an oil supply shock. Their cash distributions follow their throughput volumes, not commodity prices, so they will continue to pay even when crude or natural gas prices decline, eliminating cash flow for exploration-and-production companies.

Staying on the topic of MLPs, I want to reiterate our interest in Mach Natural Resources (MNR). Mach is an exception in the MLP world as an upstream E&P, the kind of business that is exposed to commodity price volatility. We expect it to benefit from sustained higher oil prices we expect over the second half of this year, and likely beyond. Its units, trading at $13.35, reflect none of the potential upside.

Mach is dedicated to paying out essentially all its cash flow after reinvesting 50% or less into the business. At the same time, it maintains a hedging program that locks in cash flow. The result is that the yield on its units provides downside protection, while its commodity price exposure offers significant upside amid sustained high oil and/or natural gas prices. Mach is therefore attractive as a long-term E&P income holding. For our part, we can reinvest the distributions into other high-return opportunities, which suits our situation particularly well.

We added 11,950 units to our HFIR Energy Income Portfolio at $12.69 per unit in April. The purchase added to our existing position of 7,050 units acquired on January 8 at $10.83 per unit, bringing the total to 19,000 units at an average cost of $12.00 per unit. As things stand today, the second-half setup makes Mach’s income and appreciation case stronger than it was then.

Mach Captures the Oil Upside While Maintaining Downside Protection

Mach is built differently from the shale operators it gets lumped with. It distributes its cash through a variable quarterly distribution that represents nearly all of its residual cash available for distribution. Consequently, the payout moves directly with the cash the business throws off. When an oil supply shock raises crude prices, the quarterly payout rises accordingly. The distribution structure makes Mach a long-oil instrument that happens to carry a coupon, the mirror image of a fixed-dividend producer that buys back stock and pursues other capital allocation policies that are questionable in terms of the value they add for shareholders.

Mach’s dividend also makes it far better protected on the downside relative to its E&P peers. The company’s cash operating cost runs near $11 per barrel of oil equivalent, and its corporate decline rate is roughly 17%. By contrast, Permian shale peers run $15 to $20 per barrel of oil equivalent and decline at 30% to 40%. I covered the figures at greater length in previous articles. The same commodity price slump that can wreck a high-cost, high-decline operator barely dents Mach because its low costs and slow decline keep the distribution flowing when crude falls.

The Hedges That Capped the Upside Are Rolling Off

The obvious objection to Mach’s second-half cash flow story is its hedges, which cap the extent to which it can capture higher oil prices. Look closer, however, the cap is smaller than it appears.

As of the first-quarter report, Mach held fixed-price swaps on roughly 2.5 million barrels of oil at $65.87 per barrel through the end of 2026. It also held a costless collar on another 459,000 barrels, with a $ 78.24-per-barrel ceiling. Those are real caps. But these positions run through the end of 2026, and the share of second-half barrels they cap shrinks with every month that settles. By the second half, roughly 60% of Mach’s oil is either unhedged or newly collared around current prices. Those barrels will likely realize a crude price in the $90s, not the $66 per barrel that the legacy swaps locked in.

So while the cap is not gone, it’s loosening, quarter by quarter. And how much stays unhedged is management’s call, not the market’s. The existing book covers about 38% of second-half oil, roughly their historical pace, so most barrels will realize the higher price. Holding the percent of hedged production flat, the upside will flow through. On the other hand, if management opts to hedge up defensively toward 80%, the quarterly distribution will be reduced by $0.05 to $0.06 per unit. The point for unitholders is that the hedge book plays a large role in the extent of Mach’s income increase, not in whether it increases.

Management Is Already Drilling for $95 per Barrel Oil

Mach is not waiting for higher prices to help. On the first-quarter call, management laid out a real-time pivot toward oil. Effective May 1, it moved a rig into the oil-bearing Agogo formation in Kingfisher County, where it has drilled more than 250 Oswego locations, and paused the deep Anadarko dry-gas program. The shift adds three oil-weighted rigs, with a possible fourth in the Permian Clearfork. Drilling economics are driving this decision. Oswego wells return 90% at $75 per barrel WTI and 145% at $85 per barrel, and management pegs the Clearfork at a 100% rate of return at today’s prices. Mach’s chief financial officer, Kevin White, added that the oil wells carry shorter cycle times than the deep gas program, so the shift should help this year’s cash generation rather than delay it. This is the rare pivot that costs nothing in additional capital, with management holding its reinvestment rate below 50% of operating cash flow while tilting the production mix toward the most profitable barrels.

Second-Half Cash Flow Rises Even Against the Hedge Cap

Looking at hedged and unhedged production, the surge in cash flow is significant. The table below shows the results of my model for Mach’s second-half distributable cash flow across three oil price scenarios. It maintains the oil-weighted production mix and the current hedge book, and adds the costless collars as prices rise.

In the base case at $95 per barrel WTI, roughly the level currently implied by observed global inventories, second-half cash available for distribution runs about $244 million, versus $107 million in the first quarter. That would lift the quarterly distribution from the $0.64 declared for the first quarter toward $0.73 per unit, a gain of nearly 14%, even after the model concedes about $56 million of hedge-settlement losses and a heavily gas-weighted volume base. The unhedged marginal barrel drives the variable distribution, and at $95 oil, more of those barrels arrive every quarter.

At the bear case of $85 per barrel WTI, the distribution roughly holds at the first-quarter level.

A meaningful cash flow ramp requires WTI to trade at or above $95 per barrel. While the drag from hedges upon cash flow is genuine, the bulk of the drag is attributable to the company’s legacy swaps at $65.87, which will roll off. This is therefore not a permanent ceiling, demonstrating that the cap mutes the increase in cash flow but does not erase it.

The cash flow generated in these scenarios also implies a value for the units. Annualize each scenario’s second-half distributable cash flow to a full-year run rate, about $412 million, $488 million, and $560 million, and capitalize it at a 12% free cash flow yield, which is in the ballpark of what the market tends to demand for a variable-payout E&P. On the 168.2 million units outstanding as of the first-quarter report, the implied unit price stands at roughly $20.41 in the bear case, $24.18 in the base case, and $27.74 in the bull case, 53%, 81%, and 108%, respectively, above the current unit price of $13.35.

Even the bear outcome puts the units well above our $12.69 April purchase price, while the base case represents nearly a double. These are sensitivities, not price targets, but they show what the second-half cash flow is worth once the market values it on yield rather than on a multiple of reported earnings.

Leverage Falls Without Touching the Distribution

Because Mach distributes nearly all of its residual cash, its leverage improvement will come less from debt retirement and more from EBITDA growth. My model shows annualized second-half net debt-to-EBITDA falling from about 1.22x at $85 per barrel WTI to about 1.04x at $105 per barrel. That brings the company close to management’s roughly 1.0x target, with no retained distribution.

So while net debt barely moves, EBITDA in the denominator of the leverage ratio increases with oil prices, causing the ratio to fall even as cash is distributed to unitholders rather than allocated to debt repayment. This is why management can credibly promise both a rising distribution and a falling leverage ratio. Management has been explicit that it will achieve its leverage target through EBITDA growth, not by cutting the payout. In fact, CEO Tom Ward likened the quarterly distribution to getting Christmas four times a year, implicitly rejecting the idea of trimming the payout to fund debt paydown.

What Would Break the Thesis

This analysis views Mach as a long oil position, so the primary risk relates to oil prices. A sustained move in West Texas Intermediate back below roughly $70 per barrel would reduce the cash flow benefit from unhedged barrels and push the distribution back toward first-quarter levels.

The second risk is execution. Pausing deep Anadarko gas while the oil rigs ramp could cut gas volumes faster than oil replaces them. If total output slips meaningfully below Mach’s roughly 158 Mboe/d production base, the cash-flow math could weaken.

Finally, management could allocate more residual cash to debt than to distributions, which would still be a win for the units but not for income. Unitholders should keep in mind that a variable distribution that ramps up also ramps down. None of these risks is hidden, and each is worth watching.

Conclusion

Mach offers one of the best risk/reward propositions among oil and gas E&Ps. Its variable distribution turns a rising crude price directly into rising income, and its cost structure defends against downside risk. Loosening hedges, an oil-weighted drilling pivot, and quick organic deleveraging all point to a higher payout and a lower leverage ratio from the same cash flow.

However, the call lives and dies with oil prices. If WTI reverses hard, the company’s distribution will give back much of the gain, and the hedge book will cap the top of any spike. I think that is the right risk to take here: a low-cost, long-life asset base bought below the value of its proved reserves, run by a team that treats the distribution as sacred.

We continue to own Mach in the HFIR Energy Income Portfolio and would add it at current prices. The April purchase at $12.69 looked like a deep value call on a misread secondary offering. Three months later, with WTI in the $90s, rigs already heading toward oil, and the stock trading only 5% higher, it is an undervalued current income call with capital appreciation, too.

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

Gaslighting

1. Psychological manipulation of a person usually over an extended period of time that causes the victim to question the validity of their own thoughts, perception of reality, or memories and typically leads to confusion, loss of confidence and self-esteem, uncertainty of one’s emotional or mental stability, and a dependency on the perpetrator.

2. The act or practice of grossly misleading someone especially for one’s own advantage.

- Merriam Webster Dictionary

I did not come up with this article title. It was inspired by Nelson Wu of Open Square Capital, whom I highly recommend. He recently published a piece titled “A Glut of Supply: Gaslighting the Market.”

It is amazing to sit here today, admiring the fastest onshore oil inventory draws in history, and watch market participants convince themselves that because WTI is trading around $92/bbl, there’s no supply issue.

Some have even taken the more adventurous route of saying that the y-axis needs to be changed to zero to avoid exaggerating the level of inventory draws we are seeing today.

What an amazing time to be alive.

Despite living through COVID, which I thought was a once-in-a-lifetime event, I can say with a high degree of confidence that there’s nothing like what we are seeing today, not even COVID.

As with anything in markets, there are people with lucid thoughts, and there are people who get bogged down by irrelevant facts, like how the y-axis needs to be fixed at zero, and never mind the fact that oil inventories can’t physically go to zero (tank bottom, linefill, etc).

But we live in a perilous time where facts are becoming irrelevant because narratives and vibes are the only things that matter.

It is what it is.

Gaslighting the Market

The global oil market has somehow convinced everyone that we do not have a crude shortage today, but instead, a product shortage.

That’s funny.

Refineries, as of this writing, continue to benefit disproportionately because of a combination of factors:

• China banned petroleum product exports. Teapot refineries used to flood Asian markets with cheap petroleum products. But thanks to the price cap, mandatory refinery utilization floor, and export ban, teapot refineries have, in essence, subsidized the Asian economies.

• Refineries without access to crude have reduced throughput to manage the crude storage available to them, further tightening product supplies.

• Governments are releasing crude from strategic petroleum reserves (SPR).

So what was once a crude supply shortage has instead reversed itself into a product shortage:

-11 million b/d of crude oil production shut-in

+5 million b/d of refinery throughput (-3 million b/d in China, -2 million b/d elsewhere)

+2.5 million b/d of SPR release

+3.5 million b/d of crude oil storage drawdown

And while I think this is arguably one of the funniest things I’ve ever seen, people have seemingly forgotten that a reduction in refinery throughput does not equate to demand destruction. Product inventories are still drawing down around the globe, so unless you had COVID-like demand destruction, the barrels are still lost; whether that’s in crude or product storage is not relevant.

But the market has successfully gaslit even the oil traders themselves into believing that crude is not in short supply. Never mind the fact that the most visible oil inventory in the world, the US, is showing the largest and fastest crude inventory draws in history; everything will be fine.

I mean, we are going to get an MOU signed tomorrow, and the Strait of Hormuz will open, right?

But I think the most amusing thing I’ve read of them all is this idea that dark fleet transits are happening under our noses and that the Strait of Hormuz is actually open to the global oil market, it’s just not being tracked.

I’m sure you’ve seen commentary from a very infamous journalist in the energy community talking about how the UAE tendered 14 million bbls without mentioning that the barrels are offered at Fujairah, the very bypass the UAE created to circumvent the Strait of Hormuz.

Or how about this one, another favorite of mine:

There are secret ship-to-ship transfers that are allowing some countries, such as Saudi Arabia, the UAE, Kuwait, and Iraq, to reduce domestic onshore crude oil inventories. I mean, the Strait of Hormuz must be open, right?

Again, facts seem irrelevant these days because people prefer to peddle narratives over reality.

So here’s a dose of reality check: we are approaching the summer months, and power burn demand in the Middle East requires these countries to burn crude oil. To satisfy domestic demand consumption, they need to increase production, which means they need to drain onshore crude inventories.

First, they need to offload some crude inventories to empty VLCCs, then they need to restart just enough production to meet the higher domestic power burn demand needs over the summer.

During peak summer burn demand months, crude volumes could go as high as 1.5 million b/d.

But the increase in production here is not relevant to the global oil market picture. These countries would never import crude, so an increase in domestic consumption through higher production has no bearing on the rest of the oil market.

So as I’m sitting here and reading these narrative pushers one-upping one another for the sake of publicity, I just laugh. I think it’s amusing.

And last but not least, we have also convinced ourselves that inventories are irrelevant.

“Why do inventories matter if Trump will just get a deal in the next few weeks?”

Yes, oil inventories are irrelevant. The market, which has “balanced” itself by drawing down oil inventories excluding China at 5.5 million b/d, does not care about inventories because inventories are the only thing preventing us from an outright shortage today.

Well, I hate to break it to you, but we are 6 weeks away from global onshore crude inventories including SPR reaching operational minimums.

Read more

Long 420 Jan 2027 BNO calls, strike $60, for $6.80, or $285,600.

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

Wow, this is incredible.

Goldman conducted a survey that showed 839 respondents were overwhelmingly bearish on oil.

That’s incredible. I have traded oil since 2019 and followed the oil market closely since 2015. So it’s ironic that I can tell you precisely at each major point in the oil market over the past decade how accurate this survey is.

Hint, these guys are contrarian indicators.

• End of 2016: OPEC+’s first production cut since the start of the oil price war (late 2014).

The survey was very bullish on oil. The OPEC+ production cut wasn’t implemented to its full effect. OPEC+, as usual, kept producing the same barrels until Saudi Arabia’s energy minister (at the time), Khalid Al-Falih, threw down the gauntlet in mid-2017 and targeted US commercial crude oil inventories.

• Middle of 2018: Iranian oil sanctions.

Of course, who can forget my favorite moment in my career so far: Iranian oil sanctions. In March 2018, the Saudis’ efforts to target US commercial crude oil inventories began to pay off. Couple that with Trump talking about leaving the JCPOA and sanctioning Iranian oil exports, and oil prices entered an uptrend.

Survey participants were more bullish in mid-2018 than they are today, despite Iranian oil sanctions impacting only ~1.5 million b/d, whereas we are losing ~11 million b/d today.

This is stupidity at its finest.

• March 2020: COVID.

As the saying goes, price changes the narrative; market participants were overwhelmingly bearish on oil after the COVID lockdowns, when the opposite should’ve been true. I vividly remember that in March 2020, I was the only one who talked about how forced production shut-in would balance the global oil market. It wasn’t until a month later that the consensus came to that view. At the time, if you were brave enough, you could have bought companies like Suncor for below PDP value (proved developed producing, aka, equivalent to net-net of value investing).

• 2022: Ukraine/Russia.

Last but not least, who can forget Russia’s invasion of Ukraine. In March 2022, the IEA wrote that Russia would lose ~3 million b/d of crude oil production. Oops, Russia didn’t lose anything, and crude exports surged contrary to expectations.

Instead, the IEA convinced everyone that production losses were imminent and coordinated a global SPR release over ~260 million bbls.

OPEC+ also began unwinding its production cuts, and the Biden administration turned a blind eye to Iranian crude exports.

But, of course, these survey participants remained bullish on oil prices throughout this period despite no visible supply loss.

What’s the takeaway here?

Do the opposite.

Whoever Goldman is surveying is so clueless as to the point of blissful ignorance.

As Sun Tzu (or Don Tzu) said, “Never interrupt your enemy when he is making a mistake.”

For anyone bullish on oil, this survey is the greatest blessing. You should print this chart out, frame it, and your future generation should thank these 839 respondents for it.

If you are one of those respondents and you are reading this article, thank you. Thank you for being so oblivious. If you don’t understand the oil math, don’t; I don’t want you to.

In the meantime, let the fastest visible onshore oil inventory declines continue. If an outright shortage is what’s needed to wake market participants up, then so be it.

We are going full speed into the wall and there’s no reversing this now.

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

There’s a funny distinction amongst oil specialists. There are the guys who solely do research, and there are the guys who only trade. I guess HFI Research is a bit unique here in that we trade oil and publish research. So yes, we put our money where our mouth is, unlike many research firms out there.

In my decade-long following of the oil market, I have never seen it this mispriced. In this article, I will detail my variant perception and why reality will hit the market like a sledgehammer.

Variant Perception

• HFI Research is the only research firm that publicly publishes EIA weekly crude storage estimates. Because of this unique edge, we are able to pinpoint “when” US commercial crude oil inventories will reach distress levels (i.e., operational minimums, ~380 million bbls, late July).

• Even if the Strait of Hormuz reopens today, we need empty VLCCs to return to the Persian Gulf to alleviate the onshore storage, which would allow Saudi, UAE, Kuwait, Bahrain, Qatar, and Iraq to start returning production shut-in. If the Strait of Hormuz reopens this very second, production shut-in won’t return for another 6 weeks (optimistically), which would guarantee further supply loss.

• China has reduced crude imports by ~3.5 million b/d, but that has only partially offset the ~11 million b/d of supply shut-in. Even if China does NOT return to the oil market, oil inventories in the West will reach operational minimums (i.e., tank bottom).

• The velocity of the SPR release will slow materially by the end of June. Government intervention policies are running out of steam, which means commercial oil inventories will feel the full force of the supply outage. US commercial crude inventories over the last 6 weeks have already seen 3 of the largest crude draws since 1982.

• Geopolitically, the Iran-US conflict is all or nothing. Either the IRGC is in control of the Strait of Hormuz or the regime is toppled; this binary scenario all but guarantees a prolonged conflict, contrary to market participants’ belief of a swift resolution.

With that, let’s talk about the mispricing.

Mispriced

Read more

By: Jon Costello

The stock market is acting as if the Strait of Hormuz crisis is over. Brent, at $98 per barrel, trades at a level justified by inventories alone, with no risk premium to speak of. The S&P 500 just closed at a record for the sixth straight session and has risen for nine weeks running, its longest winning streak since 2023, while the tech rally has shrugged off the oil spike entirely.

But it isn’t over. Iraqi production remains under force majeure, roughly 2,000 ships are still stranded in the Gulf, and the fighting grinds on, with Iran striking U.S. bases in Kuwait and Bahrain just yesterday.

I laid out the supply math in March and concluded the disruption would outlast the market’s patience. It has. This piece takes the next step by examining how a supply shock that persists for months or longer affects stocks and bonds.

The Ongoing Disruption

The ongoing loss of oil supply is structural, not a headline that will fade in a few weeks. Net of producer workarounds, SPR releases, and demand curtailment of approximately 3 million barrels per day (bpd), the market is running an effective deficit of around 5 million bpd. This deficit is too large to be met by production. Even if the disruption ended today, the barrels needed to close the supply gap would arrive in quarters, not weeks. A persistent deficit forces prices higher until demand falls to meet supply. That is the setup, and everything that follows is its consequence.

Despite this setup, the market is pricing in none of it. Sustained high oil prices act as a tax on a slowing economy, and sudden price spikes become more likely, pressuring both the economy and stock prices. The market has priced in none of this, which leaves it dangerously exposed to a severe decline.

Near-Term Supply Constraints

The buffers that absorbed supply shocks before the conflict are nearly gone. The market entered this crisis well supplied through its usual structural cushions, namely, excess commercial inventories and ample OPEC spare capacity. The deficit has drawn both down to almost nothing. OECD inventories are now drawing down to hand-to-mouth levels.

At the same time, OPEC+’s spare capacity has been crippled just when it is needed the most. Most resides in Saudi Arabia and the UAE and must exit through the same blocked Strait. Spare capacity that cannot reach a tanker isn’t spare capacity. So the deficit isn’t just draining the buffers; it’s removing those that matter most.

Medium-Term Supply Constraints

Even if a ceasefire took hold tomorrow, the supply side would remain disrupted for months. ADNOC’s chief executive says that restoring flows to 80% of pre-conflict levels would take at least four months after fighting ends, with full volumes unlikely to be restored before the first half of 2027. Furthermore, war-risk insurance has jumped from about 0.25% of a vessel’s value to 3% to 8%, which translates to between $3 and $8 million for a large tanker. Insurers are also requiring months of stability before restoring coverage.

Distance compounds the delay. Replacement barrels must travel at sea for six weeks before reaching the U.S. Gulf Coast. Reopening the Strait begins to normalize supply, but barrels do not arrive for weeks.

Long-Term Supply Constraints

Non-OPEC supply is far less able to respond to this shortfall than in past cycles. The EIA forecasts non-OPEC+ output growth of approximately 1.0 million bpd in 2026. The offshore projects in Brazil, Guyana, and Canada, which are driving most of the growth, were sanctioned years ago, and no price spike can bring them forward. U.S. shale production won’t fill the gap either. The major operators are working down dwindling drilling inventory, and few will chase a wartime price they expect to fade. The supply response will be measured in quarters and years, not weeks. And it will arrive small.

Then there is the alternative longer-term scenario in which Iran emerges from the conflict able to throttle traffic through the Strait at will. It will thereby have gained both the motive and the means to keep crude prices elevated. I would not build a thesis on that outcome, but it is a risk, and it points in only one direction for longer-term oil prices: up.

The Balance Has to Close

Read more

My variant perception of the oil market today can be best described by the following:

• The geopolitical landscape is binary: either the IRGC controls the Strait of Hormuz, or it doesn’t.

• Oil markets have yet to price in this binary outcome because oil analysts are still assuming some path to normal.

• Governments around the world have not yet come to accept this harsh reality, thinking that SPR can weather this “short-term” event, when the reality is far from short-term.

Before I continue, I need to set the record straight. I am not a geopolitical expert. I hate geopolitics because it’s never black-and-white. I was also a non-believer that Iran can or will close the Strait of Hormuz. I wrote articles in both 2024 and 2025 explaining why the geopolitical risk is like the donkey with the carrot. It’s always present but never material.

Article from 2024.

Article from 2025.

But when the facts change, you have to change your mind. In this case, there have been so many events since the start of the Iran conflict that have forced me to change my mind. Here are the most important ones:

• Following the attack on March 1, Iranian forces retaliated against GCC, not just against Israel alone (in the past). Mosaic defense came into play following the assassination of Ayatollah Khamenei. This was the first red flag.

• Insurance is not the issue preventing ships from transiting the Strait of Hormuz. This was evident in the physical implementation of the U-turn in mid-April. IRGC demonstrated that it can forcibly close the Strait of Hormuz; anything that says otherwise is delusional about the facts on the ground.

• Despite ongoing negotiations about an MOU or ceasefire, the same playbook by the Iranians is being implemented to effect: delay. Every day they delay a deal, the world loses 11 million b/d of crude oil production.

The reality is that time is not on our side. With each passing day, we are draining away our valuable onshore oil inventories. Governments around the world are releasing SPR, treating it as a short-term event when the reality is the exact opposite.

The IRGC/Iran cannot be in control of the Strait of Hormuz. Bypasses will take years to build; geographically, they will not be able to escape using the Strait of Hormuz.

In essence, my analysis of the situation leads me to one simple conclusion:

• We topple the regime (IRGC).

• IRGC controls the Strait of Hormuz.

Oil analysts are still assuming some path to normality via the diplomatic route, but the way I see it, it’s dead on arrival. There is no diplomacy here. You don’t negotiate with terrorists. So these half-ass approaches that the Trump administration is embarking on are just playing right into what the IRGC wants: wasting time.

Because the oil math is what it is. Every day you waste is another day you burn through oil inventories. Demand destruction is inevitable, especially when oil inventories in the West reach the tank bottom. Time is ticking, and we are the hostages.

The Misconception

Read more

The oil market is inefficient. Oil prices, as of this writing, are supposed to start pricing in demand destruction to prevent global oil inventories from hitting tank bottom, but instead, oil market participants care more about MOUs and fake news headlines more than fundamentals.

It is what it is.

But I’m here to tell you that we are now weeks away from hitting these operational minimums. What we are witnessing today is the fastest onshore oil inventory decline in history, and even if the Strait of Hormuz opens this very second, the inventory declines are inevitable.

Analogy

I’m going to use personal finances as a way to describe the oil inventory situation we are in.

Oil inventory = bank accounts

Tank bottom/Operational minimum = minimum balances in bank accounts

SPR release = mommy and daddy giving you money

Oil demand = spending

Oil supply = income

In March 2026, your income was reduced by 20% (Strait of Hormuz closed). You started delivering via DoorDash/Uber. You recovered ~9% of the lost income.

Now your income is down 11%.

Mommy and Daddy wanted to help. So they are giving you 2.5% to 3% of your lost income.

Now you are down to only 8-8.5%.

But you are irresponsible. So you keep spending as if you are earning 100% of your original income. Instead of eating out every night, you are doing it 6 times a week. You reduced your spending only slightly, 2%.

This whole time, you are burning through your savings.

First, you burn through the cash under your mattress (floating storage).

Then, you burn through your weed money (black market barrels, Venezuela/Iran/Russia).

Now, you are burning into your bank account (onshore visible inventories).

The most visible one of them all is your savings account (US oil inventories). You know not to touch that since it’s the account of last resort. But you just love spending money. I mean who can blame you, you have had the same lifestyle for years and every year, you spend more (1 to 1.4% more).

Now you are spending your account to the point where, in the next 8 weeks, you can see it running out of money. That’s with Mommy and Daddy giving you money to stay afloat.

What are you going to do?

1. Stop spending the excess amount of money (destroy demand).

2. Earn more money (increase supply).

Neither of them is easy. You’ve already done everything you can, so the decision is hard. It’s either you make the decision now or you run straight into the wall at full speed.

That’s where we are in the oil market today.

A Word On Satellite Data Providers

Before I continue, I want to make a quick comment on satellite onshore oil inventory providers. In my past experience using satellite firms, the data has always been revised retroactively.

Here’s a clear example. US oil inventory data, the most visible in the world, cannot be accurately forecasted by satellite providers with any degree of confidence.

In the past, 3rd-party providers used drones and helicopters to fly over Cushing to take images of the floating roof tanks to track inventory levels. Even these services couldn’t provide pinpoint accuracy, but the direction was genuinely spot on.

In this case, using satellite imagery that captures only 70-80% of floating roof tanks, with the possibility of distorted images or bad weather, should not be taken as gospel. Satellite provider datasets on global onshore storage are just a tool to gauge the general trajectory of inventories, but when a once-in-a-lifetime event like the one we are seeing today unfolds, these providers seldom offer the clarity that you want. There are guardrails in place in case the data spits out something asinine. But asinine data is what we have today.

This is the fastest most visible onshore oil inventory decline in history.

Why do we know that?

Because the US offers the most transparent oil inventory data, and we see it right in front of our eyes.

So the next time you see satellite data and think it’s the gospel, please take what I wrote here and take it with a grain of salt.

If you know how the sausage is made, you might not think highly of it after.

Full Speed Into The Wall

The oil market is like that irresponsible kid who’s still spending recklessly despite a material drop in income. That 8-week window is exactly what’s going to happen to US commercial crude storage.

Note: Includes next week’s estimate above already.

With SPR releasing 9 to 10 million bbls a week, our preliminary estimate shows another 13 to 14 million bbl draw next week. Now that US refinery throughput hit ~17 million b/d, US commercial crude draw will see the full force of the inventory declines.

This will be first seen in Cushing where inventories will reach tank bottom by the end of June.

It will then be followed up by distillate, which is 6 million bbls away from reaching operational minimums.

Gasoline storage will follow with storage ~10 million bbls away from reaching operational minimum.

Collectively, gasoline and distillate have ~16 million bbls to spare, but the reality is that another 2-3 weeks of 4 to 5 million bbl draws will put us in no-man’s land.

The equivalent of this is like living paycheck-to-paycheck. Yes, you might prevent outright shortages, but the moment there are any disruptions:

• Refinery outages

• Pipeline disruption

• Hurricane

You will have gasoline shortages. On the wholesale level, this level of inventory offers very little margin for error. Ideally, you want to be stocked up enough to leave room for unforeseen events. But thanks to much higher global gasoline and diesel prices, US refineries are incentivized to export any excess, leaving very little breathing room here.

Now, if the market were efficient, we should have punched demand in the face by now to slow the decline, but we didn’t.

Gasoline demand is flat y-o-y.

Distillate demand is slightly lower y-o-y.

Implied demand has not dropped enough to offset the incoming inventory declines. So yes, we are running full steam into the wall.

What’s even more troubling about everything I’m writing is that this was all written in stone at the end of April. The visible oil inventory draws were going to happen regardless of the status of the Strait of Hormuz. Now that we are a month and a half past the oil market breaking point, we are just going to hit the wall. There’s no other way around it.

Note: Total oil inventories ex-SPR are projected to decline at 7 to 8 million bbls per week. Total oil inventories with SPR are projected to decline at 17 to 18 million bbls per week.

Physical Shortages

I am now firmly in the camp that we will just need outright shortages to show up to wake everyone up. I can sit here and write all day about how inventories will decline and blah, blah, blah, but no one cares. It’s obvious if you look at how oil prices still respond to every fake Axios headline saying that a peace deal MOU is imminent.

I guess it really is what it is. The oil math hasn’t changed, but the market somehow believes it did because the price responded negatively. Human nature will never change, markets are inefficient, there’s no other way to describe this.

So if this means we just need to go full speed into the wall, then so be it.

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.

Focus on what’s important. In this case, what’s important is the oil math. Jawboning headlines can do wonders in delaying the inevitable, demand destruction, but the oil math is what it is.

We are now past the Memorial Holiday weekend and despite rhetoric from the Trump administration that a deal was “within hours”, both sides remain far apart on the key issues: uranium enrichment and Strait of Hormuz “toll.”

But before we delve deeper into the oil math, let’s give you a quick recap of what’s on the table:

• Both sides are trying to reach an agreement to sign a 1-page memorandum of understanding (MOU) where within the first 30 days, Iran and US coordinate to return traffic in the Strait of Hormuz back to normal and the Naval blockade is lifted.

• Iran will not charge a “toll” but will instead charge a navigation service fee for safe passage. It can’t be framed as a toll as it’s illegal, but it’s the same damn thing.

• Uranium enrichment will not be discussed in the first 30 days and will instead be deferred to the 2nd phase.

• Iran is also insisting that the sanctioned funds of $12 or $24 billion (no idea which source is right) be made available with the announcement of the MOU as a gesture of good faith.

• Iran is also insisting that the US pull forces away from the region and all regional conflicts stop (Lebanon).

Now let’s move to the oil math phase. If we assume that an MOU is signed immediately today, this is what happens.

The Reality

There are currently 143 million bbl of floating storage in the Persian Gulf. There are an estimated 2,000+ vessels stuck, so all of these vessels will want to exit.

Iran has already established what it calls the “Persian Gulf Strait Authority” or PGSA to manage the Strait of Hormuz. Before a ship can pass, it must fill out this form.

Now, as you can see, there’s nothing free-flowing about this. The paperwork aspect of this process allows Iran to delay flows. To return traffic flows back to normal, it would require transit to reach ~135 ships a day. With 2,000 ships stranded, it would take time even for the 143 million bbls of floating storage to exit.

By my estimate, even if we assume all of the vessels leave in an expedited fashion, it would take 20-30 days to exit. Meanwhile, the control almost guarantees that the inbound tanker flows will remain depressed. There are a few reasons why. Tanker owners face the following risks if they try to transit the Strait of Hormuz during this 60-day negotiation process:

• The possibility of renewed conflicts, which could leave the tankers stuck again and earning no income.

• Strikes on the tankers could result in permanent loss of income.

• High tanker rates elsewhere incentivize prioritizing other routes (US to Asia, for example) rather than returning to the Persian Gulf.

Without tanker flows returning to the Persian Gulf in volume, oil production shut-in remains unchanged. Remember the following:

• We need an estimated ~200 VLCCs to drain the onshore oil inventories first before production shut-in can return. If only a small number of tankers go into the Strait of Hormuz to alleviate onshore storage, production shut-in will continue.

• Even after the tankers come to drain the onshore storage, returning production shut-in will require weeks, if not months (for some countries). During this time period, production shut-in math continues. By my estimate, it would take 4-6 weeks to return 4-5 million b/d, and an additional 2-3 months to return the remaining 5-6 million b/d.

This timeline all but guarantees that, during the 60-day negotiation period, no meaningful amount of production shut-in will be returned, even if an MOU is signed today.

This is my variant perception today.

Oil Math

Read more

Someone recently asked me, “How are you so calm through all of this chaos?”

My answer is simple: I find all the fake jawbone headlines amusing because if the oil math were off, there would be no need for any of this mess. The more desperate the attempt to keep oil prices tamed from fake “imminent deal resolution” headlines, the more convinced I am that the oil math is right.

Today was one of those wild days. Al Arabiya, with the likes of Axios, already had a reputation for publishing premature peace resolution agreements.

It wasn’t long ago, on May 7, that the Al Arabiya diplomatic source published that securing safe passage for ships in the Strait of Hormuz was imminent. Now that it’s 14 days later, I guess there was nothing imminent about that.

But the funniest one of them all came today.

Now Al Arabiya has come out denying that it was a professional error to have attributed the breaking news to it, and they have since deleted the tweets.

Why is the oil market so susceptible to these daily fake headlines? I will explore that further later, but the important thing to remember here is that you cannot borrow conviction, and these are trying times.

Times like these require you to dig deep and assess the level of conviction in your own analysis. As I’ve been saying since the start, there is no historical analog to the level of supply outage we are seeing today. The oil specialists all agree on the production shut-in. That’s a fact. There might be some back-and-forth on 1) operational minimum/tank bottom, 2) demand destruction level, and 3) inventory storage decline pace. But the reality is simpler than that: this is the largest oil supply outage by 4x. You can be off by 1 million b/d, and it won’t change a thing.

When does the jawboning stop working?

Death by a thousand headlines has made trading oil particularly difficult, even for the physical oil traders. No one can take conviction positions in futures today without getting their daily beatdowns.

JH did a wonderful job breaking down what’s happening, so I highly recommend that you read that.

In essence, volatility in futures has forced traders to turn to options to play any upside. There is currently no price discovery because no one has the financial firepower to force it.

In an ideal world, prices should have gradually moved higher to a level that slows incoming visible oil inventory draws. This would remove the sudden knee-jerk reaction of what happens when global commercial oil inventories reach operational minimums. We are already seeing several oil hubs reach that level. Fujairah, the closest oil hub to all of this, has already reached tank bottom.

But since there’s no way to force price discovery and we have not had the intended effect on demand destruction (~2 million b/d is our estimate), we will just need to run out of commercial oil inventories before the jawbone stops working.

In my mind, it’s either the US/Iran conflict escalates again, and traders have no choice but to lock in the physical barrels needed for August, or we go straight to operational minimums.

Pick your poison.

And speaking of demand destruction, these daily attempts to keep oil prices tamed have had the opposite effect of what an efficient market is supposed to do.

Japan is releasing the 2nd-largest SPR on record, and it has vowed to keep prices at pre-conflict levels, further stimulating demand.

China is showing a demand drop of 0.4 million b/d y-o-y according to Goldman’s real-time data.

Europe is showing a demand drop of 0.7 million b/d y-o-y.

And US implied oil demand is up 0.6 million b/d y-o-y.

Japan: no change, 3.2 million b/d of demand

China: -0.4 million b/d, 16.35 million b/d of demand

OECD Europe: -0.7 million b/d, 13.1 million b/d of demand

US: +0.6 million b/d, 20.3 million b/d of demand

Net: -0.5 million b/d, total demand of 52.95 million b/d or just under ~50% of global oil demand

Look, the math is what it is. People are being lazy and assuming that a reduction in refinery throughput equates to demand destruction. It’s not. I don’t know how many times I have to say this.

In addition, it doesn’t take a rocket scientist to figure out that at the peak of COVID-driven demand destruction, global oil demand fell by ~20 million b/d. Just look at the global mobility indices, do you see an equivalent 25% in activity drop, the size of the drop we saw in COVID? Do you even see a blip?

If people want to ignore the data and focus on narratives, let them. I’m not interested in changing people’s minds because I’m here to make money. If they want to believe that, I really don’t care.

So yes, these daily jawbone attempts are keeping global oil demand higher than it should. We should already be moving towards demand-destruction levels to slow inventory draws, but we aren’t doing that. We are going full speed into the wall.

Timing

I get it. Everyone wants to know two things: when do the jawbones stop working, and when do prices reflect this?

As I explained above, you either get more conflict, which will be a catalyst in itself, or you just run out of inventory.

For this, I turn to Bennie K, whom I highly recommend along with JH.

Source: Bennie K

For me, I like to keep it simple.

There are only two regions in the world with “real” excess crude oil inventories today: China and the US.

China is a black box. No one even knows how much oil inventories it has. It doesn’t publish its data, so all 3rd-party providers are just guessing. We can estimate how much it has, but only after the fact.

I propose a simpler solution: follow the US.

Let me explain.

Since the onset of the conflict, oil barrel counters knew that the US would be the last place to draw. If you’ve been in oil long enough, you know why. The US, thanks to the US shale revolution, is in a particularly interesting situation.

US shale produces crude of a quality not needed by US domestic refineries. It produces ultra-light sweet crude, whereas US refineries require heavy/medium sour crude. Imagine playing tennis with a golf ball, and golf with a tennis ball. They are both balls, but they are not in the right sport. You can kind of get the gist.

US also benefits from landlocked Canadian heavy oil. With Venezuela as an ally now, the US also has another source of heavy crude. Because the barrels received from Canada and Venezuela usually have an API gravity below 25, we need to blend these barrels with condensate. The remaining excess gets exported. This is also another reason why the Trump administration should never ban US crude exports.

The only reason US commercial crude storage would drop is that there’s “demand” for the barrels. If there was low demand for the barrels, US commercial crude storage would build, all things equal. This is why you didn’t see a decline in US commercial crude storage at the start of the Iran conflict.

But this all changed by early April. When I wrote that the oil market breaking point was mid-April, it was because we knew from the deficit math that the world would start pulling US commercial crude storage lower. The US is releasing ~10 million bbls a week now in the SPR, and all of that implies the US is the last place with excess crude.

So the moment US commercial crude storage started to decline, I knew it was just a race against time. The demand pull would drop US commercial crude storage to an operational minimum, and the chaos would unfold. Once US crude exports get priced out, the rest of the world will suffer. The marginal barrel is gone, so everyone will have to compete for that extra 1-2 million b/d of crude. It adds up quickly.

The timing for US commercial crude storage to hit operational minimum is late July. But the market will need to price out US crude exports mid-June. Oil Bandit has already noted that US crude exports are getting priced out; it’s only a matter of time.

Why does it matter?

Global crude exports are currently down ~6 million b/d y-o-y.

US crude exports are up ~2.1 million b/d y-o-y.

OPEC+ crude exports are down ~8 million b/d y-o-y.

I think you are getting the point. The US, thanks to its excess crude oil inventory, has managed to offset ~25% of the decline in crude exports, but that will run out.

And for those of you who have followed every tight oil market scenario over the last decade, the US is always the last place to draw, and so when it’s gone, it’s gone.

As a result, from a timing perspective, the market needs to price in this operational minimum scenario for US commercial crude storage in June. Because you will literally run out of excess crude.

Conclusion

The level of jawboning has reached unprecedented levels, but it just proves to me that the oil math is on the right track. I mean, these guys literally published that a deal was imminent on May 20th, 15 minutes before the EIA released the largest crude draw in history. You can’t even make this stuff up anymore, but it is what it is. The oil math is what it is.

The oil market might be suffering the death of a thousand headlines today, but it is a real commodity at the end of the day, and you can’t print more molecules.

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.

In the past 2 weeks, observable oil inventories (satellite, oil-on-water, and EIA) declined by ~121 million bbls. Goldman published a note today also verifying the increase in visible oil inventory draws with an average of 8.7 million b/d for May.

The math is what it is. Even if the Strait of Hormuz had reopened back in mid-April, these visible oil inventory draws were inevitable.

The Math

First, we need to understand the sequencing.

• Production shut-in results in lower crude exports.

• Lower crude exports result in lower crude imports.

• The initial loss in crude exports push oil-on-water lower. But as other segments of the market boost exports (the US), oil-on-water moves higher.

• But given there’s no production restart because the Strait of Hormuz is still closed, oil-on-water is now falling again, which will push onshore oil inventories lower.

This is precisely what we are seeing in oil-on-water. Higher US crude exports will be insufficient to fill the gap.

Why?

Global crude exports are lower by ~6 million b/d in May vs last year. That’s with the US averaging 5.6 million b/d this month, or +2.1 million b/d y-o-y.

What most people may not realize is that the current export trend in the US is completely unsustainable. This week’s EIA oil storage report saw the largest crude oil inventory draw in history, and slightly lower than what we had projected. By July, US commercial crude storage will hit an operational minimum, and the market is already starting to price out US crude exports.

We estimate that the US can average ~4.6 million b/d without excessively draining crude oil inventories, which means the rest of the world will see another ~1 million b/d reduction in flow.

By July, the y-o-y global crude flow deficit will hit ~8 million b/d.

Read more

To make everyone’s life simpler, I’m going to explain why I’m long oil. I’m not going to mince words here. If you want a more detailed explanation of what I’m going to write here, read our reports. I’ve made the Breaking Point series public. Part 1, part 2, and part 3.

As of this writing, everyone who has traded oil in the last 2 months has PTSD. PTSD from what? Headlines.

As an oil trader said to me, “Death by a thousand headlines.”

So I’m going to say it here: The long oil trade works even if the Strait of Hormuz opens this very second.

Why?

Simple:

• Logistical delays. Even if the Strait of Hormuz reopens, it would take 2+ months before flows in the Middle East return to normal. Production shut-in returns will be gradual, so visible oil inventories will continue to fall.

• Every trader on the planet right now is waiting to go long in size AFTER the Strait of Hormuz reopens because they are aware of this logistical delay. Just because the Strait reopens doesn’t mean production shut-in returns. If you still don’t grasp this logic, I explained it in detail here.

• As of this writing, we are on pace to lose 1.59 billion bbls. This eclipses the ~400 million bbls released from the SPR and would force another round of SPR releases even after the Strait reopens. Yes, the inventory draws coming will force this outcome regardless.

Everyone in the oil community agrees on the math to a certain degree.

JPM:

Goldman:

Inventory draws are coming even if the Strait of Hormuz opens this very second.

That’s the whole point. That’s the entire long thesis. If your worst-case scenario is a complete reopening and the oil trade works, it works. That’s it.

What price?

True to my words, I don’t know as I explained in my mid-April write-up. Because the visible oil inventory draws are literally punching us all in the face now, it will be hard to figure out a price that rebalances that much of the supply gap.

But for context, in April 2022, the most visible oil inventory data in the world (the US) started to turn bearish. And despite no supply outages, Brent went on to hit $120 in June.

And although we are not at the same level of oil inventory in the US this time around, we are about to see the fastest visible decline in oil inventory in history. We will reach 2022 levels in 4-5 weeks. For US commercial crude storage, we will hit multi-year lows sometime in July:

Relatively speaking, and using US oil inventory as a barometer, Brent will be above $120 in a month. And that’s assuming everywhere else’s storage is flat as a pancake (zero percent chance of this happening, by the way).

What is the price?

I don’t know, but it’s not $105 Brent.

Positioning

I am very long.

This is obviously not financial advice. You do whatever you want, but I’m putting my money where my mouth is.

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.

For the past two months, prices have been flat.

In this write-up, I’m going to give you a breakdown of the following:

• Where are fundamentals today?

• Is there a trade setup?

• What about natural gas producers?

Where are fundamentals today?

Natural gas storage today stands at 2.29 Tcf, a 140 Bcf surplus relative to the 5-year average of 2.15 Tcf.

Our storage projection puts natural gas storage at 2.758 Tcf by June 12 week. The relative surplus is expected to remain the same, as fundamentals remain neutral over the coming weeks.

Cooling demand is not expected to kick off until early June, so from a catalyst perspective, we won’t see any meaningful signs of tightening until warmer-than-normal weather.

Read more

Please read the following articles on the oil market breaking point:

(WCTW) The Oil Market Breaking Point

(WCTW) The Oil Market Breaking Point Is Here

(WCTW) The Oil Market Breaking Point And How It Unfolds

We have reached the point of no return. In the past week, sellside analysts came out in unison declaring that the Strait of Hormuz will reopen sometime in June. JPM, Goldman, and Morgan Stanley are all basing their assumptions on the Strait opening “soon” and oil prices remaining around $100 through year-end.

If you are like me and have spent time analyzing the geopolitics, you may have arrived at a different conclusion. I detailed my thoughts on the endgame here.

One of the most notable reports came from JPM’s team, which noted that the Strait of Hormuz will open one way or another because we are going to hit tank bottom in global oil inventories if it doesn’t open by June.

A core assumption of our framework is that the accelerating pace of oil inventory depletion will ultimately force the reopening of the Strait of Hormuz, one way or another.

And to be totally fair to the sellside community, this type of analysis is needed for those investing in energy stocks. Some degree of return to normality is required when assessing how to underwrite energy stocks. But for the purposes of analyzing where oil prices are headed, this is not the type of analysis you want to publish.

The issue is that everyone who runs a global oil supply & demand model understands the implications. Now that we are a month past the oil market breaking point, logistical constraints make it impossible for production shut-in to restart until August.

Most ballast tankers are headed for the US to drain the last remaining excess crude in storage, and the time it will take to return to the Persian Gulf all but guarantees more delays.

And that’s assuming we actually find a resolution by June 1. If not, I reckon the consensus will be in for a very rude awakening.

This brings me to the point of this article: we have now entered the point of no return. Since the beginning of the conflict, my core thesis has been simple: every day that passes without a resolution increases the probability that there is no resolution.

Emotional and cognitive biases prevent people at the top from reaching a diplomatic resolution when the cost of anchoring becomes too great. From the US’s side, leaving now would look like a total strategic defeat, while for the Iranians, the cost of enduring the current conflict has already been spent; you will anchor down and outlast your adversary.

So to assume that the Strait of Hormuz will reopen by June 1 is just wishful thinking. I am somewhat relieved that the sellside community has not analyzed what it would do to oil prices if the Strait remains closed. When that day comes, it could be a contrarian signal to start exiting our oil long exposure. But judging by the reports I went through the past week, we are quite a ways from that scenario.

There’s nothing like price changing the narrative. I guess only time will tell who changes their tone first.

The Point of No Return

The implied oil flow for May has averaged -7.5 million b/d.

This makes sense considering the following variables:

Production shut-in: 12 million b/d

Demand loss: 2 million b/d

SPR: 2.5 million b/d

Net: 7.5 million b/d

Read more

In the past month, I’ve spent more time than I like on geopolitics. As I’ve said in the past, geopolitics usually falls into the grey area. I have never found it particularly interesting because of the lack of margin of safety. But since the Iran conflict started, I’m growing increasingly convinced this is a black-and-white issue. It’s all or nothing.

This piece is to give you some clarity on how I’m thinking about the Iran conflict and the various scenarios I see “resolving” the issue.

Demands

One thing that is worth noting is that most market participants are looking at the resolution of this conflict from the US’s perspective. Instead, we have to look at it from Iran’s.

The number one question we need to ask is: What do the Iranians want?

In my mind, it’s simple: a deterrent powerful enough that no one else will attack it again in the future.

So whether that’s acquiring a nuclear bomb, the control of the Strait of Hormuz, or a regional framework in place similar to that of NATO, Iran needs physical guarantees.

Control of the Strait of Hormuz

In a WCTW piece published on March 31, 2026, titled “The Unacceptable Status Quo And Why The Oil Market Will Never Be The Same Again.” We said that a toll arrangement is a non-starter.

From most generalists’ perspectives, the toll fee might not seem like much. A $2 million payment on cargo worth $200 million is a small price to pay, but money is not the issue here; it’s the ability to enforce traffic flow.

Following the craziness we saw on April 17, when the Iranian foreign minister declared that the Strait of Hormuz was open, the IRGC physically implemented the closure of the Strait. This was the Tom Hanks had COVID moment for me. This single event changed how I thought about the geopolitical landscape.

Again, as I explained in the “oil market breaking point is here” article, this was the first time since the conflict began that we saw tankers trying to leave in size. Prior to this, most tankers were afraid of mines or didn’t move due to insurance issues. This event clarified everything for me. The physical enforcement is going to be a major issue in the years ahead.

Now that we are nearly 3 months into this conflict, the Iranians are demanding that the control of the Strait of Hormuz be a precondition to even starting negotiations.

Read more

On April 25, we published a piece titled, “B.A.C.D Is Coming To An Oil Storage Hub Near You.” In it, we said:

From now to the end of July, visible US crude inventories will decline by ~213 million bbls, the largest and fastest decline in history.

US total liquids with SPR will fall to an all-time low.

Yes, an all-time low.

Since EIA started publishing the data in Jan, 5, 1990, US total liquids have never breached 1.4 billion bbls.

This is happening regardless of what happens to the Strait of Hormuz. It’s too late already.

Fast forwarding to today, we are on pace:

US Total Liquids With SPR

In our April 25 report, we wrote:

Starting in next week’s EIA oil storage report, the US will average over 18 million bbls in total liquid draws.

Since then, US total liquids with SPR dropped 48.846 million bbls. We have averaged a draw of 16.282 million bbls per week.

Looking at current projections, US commercial crude storage is expected to decline steadily through the end of July. Refinery throughput has picked up, which will dampen some of the product draws we’ve seen, but crude draws will remain very heavy.

As you can see from the current product storage chart in the US, we are already running low on available products for domestic consumption.

In 2022, we had a global refinery capacity shortage, which saw refining margins rise disproportionately relative to crude. US refineries were incentivized to run at full capacity all year. You can see in the green dotted line above how low product storage stayed throughout 2022.

This time around, we have a crude shortage, but the lack of crude elsewhere has incentivized US refineries to run at max capacity going into the peak driving season. Product storage is now ~13 million bbls from the lows we saw in Q3 2022. We are about 3 weeks away from US petroleum product exports falling. Once the buffer is gone in the US, the elevated petroleum product exports that the world is enjoying will disappear.

Time is running out.

Read more

By: Jon Costello

Suncor Energy (SU) has transitioned from a turnaround thesis to an execution durability thesis. Its stock price has recovered to a higher multiple, implying that the market expects operational excellence to continue. I believe it will, and that the company’s shareholders will benefit significantly from the higher oil prices that increasingly appear to be sustainable for months or quarters, rather than weeks.

Since Rich Kruger took the CEO role in April 2023, Suncor has beaten nearly every guidance metric the company has set. It delivered its entire 2024 Investor Day three-year plan a full year early. That plan called for an $8 billion net-debt floor, a US$10-per-barrel WTI breakeven reduction, 100,000 bbl/d of upstream production growth, and $3.3 billion per year of additional normalized free funds flow. The first quarter showed the discipline has carried into 2026. Adjusted funds from operations of $4.03 billion was up 32% year over year, with first-quarter records in upstream production and refinery throughput and an all-time high in refined product sales.

At Suncor’s March 31, 2026, Investor Day, management laid out a new plan for the period of 2026 through 2028. The 2028 targets: $2 billion per year of additional free funds flow at US$65 per barrel WTI, a US$5 per barrel reduction in corporate WTI breakeven to US$38 per barrel, and another 100,000 bbl/d of upstream production growth. The 10% refining nameplate re-rate to 511,000 bbl/d was already implemented effective January 1, 2026. Each target rests on concrete operating levers, namely, North Pit 2 at Fort Hills, Firebag sidetrack drillouts, refinery debottlenecking, and a trading footprint that has expanded from roughly 20 to 45 countries in two years. The new three-year plan could be more challenging than the previous 2024 plan. For the 2024 plan, the consolidation of Fort Hills and a higher initial net-debt base accelerated progress in a manner that is unlikely to be repeated going forward. Nevertheless, I expect Suncor to deliver on its new plan. At current oil prices, the company generates abundant cash flow—far more than the $2.91 billion of free funds flow it generated in the first quarter alone—and management is directing all free cash flow to building value per share rather than squandering it on acquisitions or increasing size at any cost, as so many E&P management teams have a habit of doing. Suncor now has more robust earning power than it has had in over a decade, and as long as management’s discipline holds, its share count is set to shrink every quarter into the future, which is all but certain to increase value for its shareholders.

Read more

By: Jon Costello

Mach Natural Resources LP (MNR) reported first-quarter 2026 results on May 7, the first clean look at the company’s performance since its IKAV and Sabinal acquisitions closed last September. I added units at $12.69 in early April after the non-dilutive secondary offering triggered a 10% selloff, and came into earnings seeking confirmation that the combined business is integrating on plan. The integration is on plan, and the value case I laid out in April still holds at the current $14 unit price.

Operations Pivoting To Oil

The most consequential development of the quarter wasn’t in the numbers. Rather, it was CEO Tom Ward’s decision to pivot the rig program back toward oil. Starting May 1, Mach moved its first rig into the Oswego in Kingfisher County, where the company has drilled more than 250 wells since 2021, and the 2025 program sported a 39% IRR at $57 WTI, rising to 87% with WTI at $75 and 145% with WTI at $85.

Mach also paused its Deep Anadarko dry gas program and is planning to add up to two more oil-weighted rigs. The company is weighing adding a Clearfork rig in the Permian in place of the San Juan Mancos completion program. Returns from Clearfork are around 100% at current oil prices.

With WTI in the $90s and Henry Hub hovering just under $3, the shift toward oil is the same oil vs. gas “toggle” that Ward described on Mach’s fourth-quarter earnings conference call, just running in reverse. The company can flip back to gas the moment gas prices offer better returns.

Production during the quarter averaged 157.5 MBoe/d, up 95% year-over-year. Essentially all of that gain came from the IKAV and Sabinal acquisitions, as organic production from the legacy Anadarko base was essentially flat. The company’s production mix is now 16% oil, 70% natural gas, and 14% NGLs. Importantly, unit costs are moving in the right direction: LOE per Boe came in at $7.12, down from $7.50 in the fourth quarter of 2025, a 5% sequential improvement that indicates the acquired assets are integrating on plan. The 2026 capex range of $315 to $360 million remains intact.

Meanwhile, the San Juan story is unchanged. Mach holds 570,000 net acres in the basin, the Mancos shale continues to perform at the high end of expectations, and 65% of basin volumes are committed under the BP take contract at $1.72 per Mcf through 2030. This contract is one of Mach’s most underappreciated assets, given where the uncontracted San Juan basis is currently transacting.

Robust Cash Generation

The first quarter was noisy in terms of GAAP but clean at the cash level. Revenue of $285.9 million was up 26% year-over-year but down 26% sequentially, and Mach reported a $35.0 million net loss versus $15.9 million of net income a year ago. The cause was a $96.9 million derivative loss, almost entirely an unrealized mark-to-market loss resulting from rebounding oil prices relative to the company’s hedges.

Strip out the derivative noise and the underlying business actually delivered. Adjusted EBITDA of $194.6 million was up 22% year-over-year and 4% sequentially. Cash available for distribution of $107.4 million was up 22% sequentially and 14% year-over-year. Mach declared a $0.64-per-unit distribution, up from $0.53 in the fourth quarter of 2025, consistent with the framework of paying out essentially all distributable cash after a sub-50% reinvestment rate. The first quarter’s reinvestment rate came in at 41%. The blended realized price was $25.78 per Boe pre-derivatives, down 26% year-over-year, dragged down by gas at $2.74 per Mcf.

On the balance sheet front, net debt was $1.082 billion at quarter-end, putting trailing leverage at roughly 1.3x Adjusted EBITDA against Ward’s 1.0x target. That gap is a binding constraint on capital allocation. Ward called the leverage “a pebble in my shoe” on the call and made clear that M&A will be on hold absent an all-equity deal that is accretive to distributable cash. He also confirmed he won’t cut the distribution to pay down debt. Rather, leverage will normalize as commodity prices recover, driven by EBITDA growth. With $358 million of liquidity, Mach has the room to keep paying out at current prices and wait for gas to firm.

Value in Excess of the Unit Price

At Mach’s current unit price of $14, the value on offer to equity investors is ample. The company’s enterprise value stands at approximately $3.4 billion, comprised of roughly $2.3 billion in market cap 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 under an average WTI price of $65.34 per barrel and an average natural gas price of $3.39 per MMBtu.

Today, WTI trades at $98 per barrel and Henry Hub natural gas at $2.90 per MMBtu. The reported PV-10 was calculated using SEC pricing of $65.34 WTI and $3.39 per MMBtu Henry Hub — well below today’s $98 WTI and $2.90 Henry Hub. Even under those conservative price assumptions, PV-10 covers more than 90% of the enterprise value. Recalculated at current commodity prices, the reserve value comfortably exceeds the entire enterprise value, implying the market assigns essentially zero value to owned midstream infrastructure, future development upside, and continued growth through future accretive acquisitions.

Using Mach’s first-quarter 2026 realized price strip of roughly $72 per barrel WTI, the company generates approximately $0.60 per unit per quarter, or $2.40 annually in distributions, resulting in a 17.1% distribution yield at the current $14 unit price. First-quarter 2026’s actual declared distribution of $0.64 sits modestly above that model output, with the gap attributable to NGL realization and minor mix effects. The following table illustrates my estimates for the company’s cash flow sensitivity at different commodity prices.

The company’s earning power is more robust if commodity prices remain elevated and it locks in higher prices through its programmatic hedging. Without hedges, it could generate approximately $2.85 per unit, representing a 20.4% distribution yield.

These estimates assume a first-quarter WTI price of $72 per barrel, a production mix of 55% Mid-Continent, 38% San Juan, and 7% Permian Central Platform, and that NGLs are priced at 35% of WTI.

Mach’s investors will fare very well from an income perspective, and as the company pivots toward oil—and if the structurally higher oil prices we expect become consensus—then it is only a matter of time before the unit price increases to compress the distribution yield to between 8% and 12%.

Risks to the Investment Thesis

Downside risk to unitholders stems from lower commodity prices, higher capex, and higher cash interest on the company’s credit facility. Additionally, Mach’s edge has always been buying assets at or below the value of their currently producing reserves, but that supply of distressed deals tightens as commodity prices rise.

Another potentially material downside risk stems from San Juan’s uncontracted prices. The 35% of Mach’s San Juan gas production that isn’t locked into its contract with BP sells at whatever price the local market will pay, and that local price is currently around $1.00 per Mcf, well below the national Henry Hub benchmark, because there isn’t enough pipeline capacity to move San Juan gas to higher-priced markets in the Pacific Northwest, Phoenix, or Mexico. Mach’s outlook assumes new pipelines and LNG terminals open up over the next few years to absorb that gas. If those projects get delayed, then the local San Juan price could fall even further below $1.00, dragging down Mach’s blended gas realization regardless of what Henry Hub prices do.

On the financial side, leverage above target constrains the company’s capital allocation. Its borrowing base is reset twice a year based on commodity-price assumptions. Its revolver carries variable interest rates, and the open hedges will remain a drag on cash flow until the swaps roll off.

Conclusion

The first quarter didn’t change our investment thesis for Mach. The company’s PV-10 still covers nearly the entire enterprise value at SEC pricing, and would more than cover it at current commodity prices. The 25% multiple discount to C-corp peers remains, and the variable distribution still delivers oil-price strength directly to unitholders. At a mid-teens yield backed by sub-$40 WTI breakeven economics, I’m holding and plan to add to the position if the units dip back toward my $12.69 cost basis.

Link to HFIR Energy Income Portfolio on RunPlutus.

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

Price drives narrative. At least that’s what’s happened to the energy community in the past week or so. The consecutive successive attempts by Axios and the Trump administration’s daily attempts at jawboning oil prices have effectively changed the specialists’ minds.

“Perhaps we aren’t going to have an oil shortage... after all?”

The amount of myopicness in the oil market today is at an all-time high. Barrel counters have seemingly forgotten the simple fact that there are storage facilities that are unobservable by satellite data: products and underground storage.

So instead of coming to the logical conclusion that the 12 million b/d of production shut-in is known, and the inventory draws in unknown storage tanks are unknown, they have seemingly flipped the facts around.

I suppose these are crazy times, and it goes to show just how few people can have lucid thoughts these days. Only time will tell who is eventually right.

Shortages

We are now so far past the point of no return that there is no point of returning back to the status quo. I’ve been getting asked questions like, “What happens if the Strait of Hormuz reopens today?” But these questions fail to answer one important question:

Who will control the Strait of Hormuz?

This single event will have an immense impact on the future trajectory of the oil market. As I have said since the beginning of the Iran conflict, the Strait of Hormuz card cannot be played again. Either Iran controls it, or the regime is toppled. There is no middle ground. This is all or nothing.

This simple distinction is what sets my understanding of the conflict apart from others. The consensus still believes there will be a framework to allow a gradual reopening or for Iran to charge a toll. No, these are all nonstarters. Either they get control, or they don’t; there’s no other way around it.

So it’s interesting to see sell-side analysts like JPM talk about how the Strait of Hormuz will reopen by June because global oil inventories are headed for a tank bottom, as if this scenario somehow resolves the geopolitical conflicts.

Wishful thinking much?

But again, it is what it is. If they are going to think like that, let them. I’m not interested in changing people’s minds at this point. I’m here to make money, and I’ve already put my money where my mouth is.

This brings me to the point I want to discuss. Perhaps the market will only care about outright shortages at this point before pricing in demand destruction. Maybe the market is inefficient, and we just have to force shortages down its throat before it inflects.

So what does the timing look like?

Read more

Editor’s Note: This article was first published to paid subscribers on April 27, 2026. This article is public.

In our April 19, 2026 WCTW report titled, “The Oil Market Breaking Point Is Here.” We said:

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

Over the coming weeks, if the Strait of Hormuz remains closed, sell-side analysts will try very hard to “forecast” an oil price only to fall short initially. As I’ve explained before, there’s no historical precedent for what we are witnessing in the market today. The only way to offset the supply loss of ~11 to ~13 million b/d is through COVID-like mandated lockdowns.

Outside of government-mandated lockdowns, market-led demand destruction of this magnitude has never occurred. Even during the Great Financial Crisis of 2008, we did not see demand destruction anywhere near ~12% of global demand. The only relevant timeframe was from 1980 to 1983, when global oil demand fell by 10%, but that was over 3 years. This time requires an instantaneous rebalancing to prevent oil inventories from hitting the tank bottom.

Again, no one, especially not us, can provide you with an accurate oil price forecast. Instead, I will walk you through the logistical roadmap of what I see happening.

Roadmap

We are already past the oil market breaking point. As we explained in our initial oil market breaking point article, cumulative storage lost (including reopening) is now 1.2 billion bbls.

From here on out, oil market will follow the logic I explain below:

1. We have now exhausted excess oil-on-water and floating storage. Every barrel that declines now will be in the form of crude storage, product, or demand destruction.

2. Refineries with a lack of crude in storage will first reduce throughput. They will increase buying to compensate for the lack of crude. This buying will be in the form of higher backwardation in the prompt months. As a result, crude timespreads will remain steeply backwardated.

3. Given that the supply outage is concentrated in crude, refining margins will remain elevated in the regions with no excess in crude. Asian refining margins, for example, are very elevated today, assuming you have access to crude. Regions with not too much excess in crude, but also no material shortage in products will see refining margins compress (think Europe). Regions with both excess storage in crude and products will see refining margins elevated (think North America).

4. Because the shortage is in crude, Asian refineries will not be able to access the crude they need, so they will start importing products. Product demand from the East will pull higher refining margins from the West. Europe’s refineries will see a bump in refining margins, allowing them to afford the elevated cash crude price. The US will also be dragged higher, incentivizing higher throughput.

5. All the while this is happening, refining margins will remain elevated worldwide. This signal basically indicates there’s no demand destruction yet.

   ---

   Note: We are now entering this phase below.

6. This step is when things get interesting. Product storage will get low in the West (inside a month for both Europe and the US). Refineries will be incentivized to keep products at home because domestic prices have reflected better economics. Now Asia will have both a crude and a product shortage. Asian refining margins will take another leg higher as the outright shortage translates into even higher product prices. Asian refineries, seeing the surge in margins, will have room to bid at any price for crude on the physical market. This will start to pull more crude from West to East.

7. Refineries in the West (the US and Europe) will all of a sudden have to compete against Asia for this increase in demand. This now becomes a bidding war among all the refineries over the crude shortage. The US, which previously had a surplus in crude inventory, will start bidding aggressively to keep barrels at home. Brent - WTI spread would collapse as a result.

8. As refineries start competing aggressively for crude, prices will not follow the usual linear pattern but will follow a parabolic pattern. The ripple effect will be that both refining margins and crude prices rally in tandem until one of those breaks.

How do you spot the eventual turning point:

• First, global refining margins will fall as end-user product demand declines. Margins will remain positive. Refineries that can access crude will still be able to make money, while those unable to access it will have to shut down entirely.

• Second, crude timespreads will start to fall. Backwardation will narrow. Refineries unable to compete for crude oil due to compressed margins will fall by the wayside. This incremental change in demand is the 2nd red flag.

• Third, global onshore inventories will stop declining. Product demand destruction will first translate to a flat line in product storage. Once refinery throughput falls enough, crude storage will also have bottomed.

• Finally, the combination of falling refining margins, falling crude timespreads, and lack of decline in onshore storage will signal to us that the physical oil market has rebalanced.

From an oil long standpoint, you want to sell your positions when the crazy bidding war starts. There’s no telling how high prices can go because it’s dependent on how much the end-user can handle. Marginally, we will lose some demand each time prices rise, but no one can forecast exactly how much. The only way we can measure that will be through real-time data like flights, mobility index, satellite storage data, and refining margins.

Coincidentally, when the shortage actually shows up is likely when the generalists will panic. We have developed sentiment indicators to identify the eventual turning point. I like the use of the term “contrarian indicator” here for people who can’t correctly understand the current outage. These are likely the same individuals who will get bullish oil at precisely the wrong time.

The Ripple Effect

Asia is the most dependent on the Strait of Hormuz oil flow, so it was always the first region to be impacted materially.

First, all poor countries will face fuel shortages, but as these shortages shake governments, panic buying will pull demand away from wealthier Asian countries.

This ripples into increased buying for crude from wealthier Asian countries. This starts to tighten crude supplies from the West.

Higher buying from Asia tightens crude storage in the West, forcing refineries there to compete to keep barrels at home.

We are 2-3 weeks away from this last step. Onshore oil inventories in the US will have to decline first, and since the US is releasing the largest amount of volumes from the SPR, the bid for US crude will continue. That is, until the US runs out of excess crude...

Editor’s Note: The above chart has been updated with the latest figures. The same forecast for the end of July holds.

Using the current tanker flow activity, US crude exports are expected to remain elevated until the end of June. As for after June, I think the tighter crude storage environment will start to pressure US crude exports lower. This will then manifest into even higher buying pressure from Asia.

The troubling thing about everything I’m writing is that now that we are here in the breaking point timeline, even a full reopening of the Strait of Hormuz in early May will ensure that no real flows to Asia occur until mid-July.

How will the market keep balancing the ~11 to ~13 million b/d outage until then?

I don’t know, but price will have to do most of the heavy lifting.

Asia ex-China is already seeing the steepest drop in crude storage in history. Most of those barrels belong to Japan and South Korea, so the lack of crude in storage will create the panic buying we described above.

The ripple effect is underway now. It’s too little too late.

It is what it is...

The oil math is hard to fathom, but we’ve never been in this situation before. We’ve never had an outage anywhere near 11 to 13 million b/d. As I wrote before, none of the energy specialists disagree on the math because we used to argue over 500k b/d to 1 million b/d. Once the outage reached this size, arguing between 11, 13, or 9 million b/d becomes irrelevant. The level of demand destruction needed to balance the market will be either 4x or 6x that of the previous recession. You see, it starts to lose meaning after a while.

And unlike most sellside analysts, I can’t tell you what price everything will settle at. If they were intellectually honest, they would tell you the same. The sequencing I explained above requires us to react in real-time. There’s no predetermined outcome here. We can only assume the price will be higher than today’s because demand has not fallen anywhere near 11 to 13 million b/d.

Instead, the point of the article is to offer you the roadmap of how I see the events unfold. To recap the turning point:

• Refining margins will fall first.

• Crude timespreads will materially lose the backwardation.

• Visible onshore inventories start to bottom.

So long as we are equipped with the tools to spot the turning point, I know I am well prepared for the scenarios ahead. In the meantime, let the geopolitics do its thing; we can only focus on the things we can control.

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.