Previous write-ups on Calumet:

(Idea) Calumet Shares Sell Off Despite A Brightening Outlook

Special Situation: Calumet

(Idea) Calumet - The Next Special Situation Idea

(Idea) An Important Update On Calumet

By: Jon Costello

The price of biofuel compliance credits has doubled this year. For Calumet , the D4 RIN credit, upon which its Montana Renewables’ biofuel economics depend, traded at $2.42, just shy of its highest level since 2021. We have owned CLMT in our HFIR Energy Income Portfolio since June 2022, and in my May 20 article, I revised my valuation higher to approximately $50 per share as renewable diesel margins normalized.

CLMT shares are taking a hit, along with the broader energy sector, after the U.S. officially signed a memorandum of understanding with Iran to end hostilities. The shares currently trade around $31.75, back to where they traded when my previous article raised my valuation and well below my fair-value range, leaving the risk/reward unusually attractive relative to the upside potential in the shares.

This piece takes an unusual tack for my articles. It offers an ultra-bullish way to size the upside potential in CLMT shares. Specifically, it takes the cash CLMT’s renewable business will throw off in the back half of this year, assumes the market treats that windfall as permanent, and estimates where the stock might land in that scenario. To be clear, I don’t believe the windfall will be permanent. But the gap between what the RIN market is signaling and what CLMT equity now reflects is wide enough to be worth measuring.

Why RIN Prices Doubled: A Mandate the Industry Can’t Meet

First, it’s probably worth reviewing what a RIN actually is. “RIN” is short for Renewable Identification Number, a credit generated each time one gallon of biofuel is produced. The federal Renewable Fuel Standard requires that refiners and fuel importers blend a set volume of biofuel into the nation’s petroleum supply each year, and the required volume is called the Renewable Volume Obligation, or RVO. A refiner meets its obligation in one of two ways. It can blend the biofuel into its refined products itself, or it can buy the RIN credits from another party that did. When the federal RVO mandate is set above the level the industry can comfortably supply, refiners have to bid up RIN prices to pull every last gallon into the market.

Fortunately for CLMT and its peers that survived the brutal biofuel market over the past few years, the 2026 and 2027 mandates are the most aggressive in the program’s history, and the industry is nowhere near meeting them. In a June 10 analysis, agricultural economists Todd Hubbs and Scott Irwin estimated that required biomass-based diesel RIN generation must rise from 7.10 billion in 2025 to 10.99 billion in 2026 and 11.89 billion in 2027, which the researchers refer to as “levels that have no precedent in the history of the U.S. biomass-based diesel industry.” Actual output has been running well below the pace needed to hit the 2026 figure. The authors further state that closing the gap would require monthly production “more than 20 percent above the highest single month ever recorded,” sustained for the rest of the year. This is something the industry cannot do. So the RIN price should climb until demand is rationed.

Adding to the bullish picture is that the 45Z tax credit works against biofuel imports, thereby preventing a surge of foreign biofuels from substantially dampening the setup for domestic producers.

D4 RIN prices have already begun to surge, trading at $2.41 on June 18, near their 2021 record and 100% above their price at the start of this year. Because a gallon of renewable diesel—the biofuel produced by CLMT—generates 1.6 to 1.7 RINs, the EIA notes that these fuels “currently generate more than $3.50/gal of credits.”

The academic supply work, the EIA price series, and the futures market all indicate that a mandate the industry cannot physically meet is on course to trade to—and potentially exceed—its record price.

Moreover, risks to the RIN price outlook are easing. One such risk noted by the authors of the farmdoc article was that the oil price spike related to the Iran conflict could curb gasoline and diesel demand. Since the RVO sets the required biofuel volume as a fixed percentage of the petroleum gasoline and diesel supplied each year, a price spike that curbs fuel demand would shrink the obligated volume base to which the percentage applies, and with it, the volume of mandated biofuel blending and the demand for RINs. That risk has now receded with the United States and Iran introducing a framework to end the war and reopen the Strait of Hormuz. In response, WTI dropped by roughly one-third from its 2026 highs under $74 per barrel. With demand more likely to hold steady, the biofuel blending mandate will likely remain firm.

The U.S.-Iran deal helps on a second front, as well. A severe escalation would have driven refined-product prices high enough to crush end-user demand and destroy refining margins. Instead, with WTI prices easing and demand holding, the 2-1-1 crack spread is more likely to firm, a tailwind for asphalt production at Montana Renewables, which sits alongside the renewable plant.

Montana Renewables Is Net-Long RINs

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By: Jon Costello

Previous write-up: (Idea) Genesis Energy - The Only Independent Gulf Of America Pipeline Operator Is At An Inflection Point

Genesis Energy gave its unitholders reason to worry in the first quarter of 2026. The company’s offshore segment that anchors my thesis came in below management’s expectations, and management cut its volume outlook for Shenandoah, the marquee project behind the cash-flow inflection I have written about for the past two years. Furthermore, its bank leverage ticked up to 5.38x.

The units responded by falling from around $17.60 at my April write-up to roughly $14.4on the print. To add insult to injury, last week’s news that BP (BP) has started a process to sell stakes in two of its Gulf of Mexico projects knocked the units down further to $15.00.

Despite the negativity in the market, Shenandoah’s issues only dent the investment thesis rather than break it. To be sure, the risk is real. But management’s discussion of Shenandoah’s reservoir dynamics should assuage the concerns. The selloff therefore represents an opportunity to buy into a business that is midway through a cash flow inflection that I believe will accelerate deleveraging and add value for unitholders. We continue to own the units in the HFIR Energy Income Portfolio, and GEL remains a top income pick in midstream and energy.

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By: Jon Costello

Energy investors regularly face the tradeoff between growth and safety. At the moment, the choice is more difficult than usual. Higher oil prices have significantly increased the prices—and, in many cases, the attractiveness—of E&Ps. Many are now at levels that imply little to no margin of safety if hostilities in the Middle East cease and oil prices fall. More broadly, the S&P 500 sits near record highs, and a deepening oil supply shock is exactly the kind of event that could end the run.

Even safety is hard to find. The typical safe haven, Treasuries, no longer look safe. The federal government’s fiscal position has raised questions about the prospects for longer-dated bonds.

So where is an income investor to go? I believe one of the best alternatives remains midstream oil and gas MLPs. These instruments offer the combination of tax-advantaged income, high income yields, and cash flow that will hold up through a shock.

Stock Prices Are Stretched and Treasuries Are Compromised

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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

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Editor’s Note: HFI Portfolio has already sold long positions in Kronos, Tronox, and Chemours.

By: Jon Costello

I made the bull case for Kronos Worldwide (KRO), Tronox Holdings (TROX), and The Chemours Company (CC) in November 2025 and reiterated it in a February 2026 chemicals piece. That thesis was right in terms of price action, as the names rallied. However, the macro conditions that underpinned it no longer exist. It is therefore time to take heed of the risks these producers face, and trim or sell titanium dioxide positions.

The Original Bullish Setup

The original thesis published in November was premised on cyclical supply-side developments. Roughly 1.1 million metric tons of global titanium dioxide capacity had been curtailed in the 10-million-ton market. Anti-dumping regimes in the U.S., the European Union, Brazil, and Saudi Arabia were removing approximately 800,000 tons of low-cost Chinese supply from the system. Venator’s insolvency helped clear the inventory overhang and left the industry with a “Big Four” oligopoly. Customer flight to scale was driving paint and coatings buyers toward Kronos, Tronox, and Chemours.

The demand assumption on which the thesis was based was for a constructive outlook for U.S. consumer spending, the primary driver of the U.S economy. The One Big Beautiful Bill Act was set to add as much as $100 billion to refunds in the 2026 tax season, with the average filer receiving $300 to $1,000 more than in a typical year. Moreover, there didn’t appear to be any systemic economic issue on the horizon poised to cause an imminent or unusually severe recession.

The recovery thesis needed two things to play out. Supply had to stay disciplined, and demand had to hold. The supply side is still doing its job. But the demand side is no longer reliable.

The Worst Oil Supply Disruption in History Changes the Picture

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By: Jon Costello

(Idea) Cardinal Energy - Transitioning To An SAGD Growth Company

Note to readers: Figures are in Canadian dollars unless otherwise specified.

Cardinal Energy (CJ:CA) released first-quarter 2026 results on May 7, 2026. The results marked a milestone in the company’s move away from conventional producing assets and toward steam-assisted gravity drainage (SAGD). Its Reford 1 SAGD project produced above nameplate capacity, the board sanctioned a second SAGD project at Reford 2, and the balance sheet was repaired via a $104.7 million bought-deal common share offering.

I’ve liked Cardinal since I initiated coverage in 2023, and I bought the company’s $7.00 strike warrants in size at $0.44 in April 2025. The question today is whether the stock is worth buying at its current price of $11.80, or whether investors should wait for a selloff before buying. For the moment, the valuation work points to the latter.

Why I’ve Liked Cardinal

My August 2023 article carried a buy rating and a $10-per-share price target. That represented 40% upside from the $7.15 trading price at the time. The bull case was based on a discounted cash flow value of $9.69 at US$80 per barrel WTI and a 10% dividend yield. The reserves report showed an $18.54-per-share NAV with an 11-year reserve life.

The bull case was that Cardinal offered the best risk-adjusted income proposition among Canadian conventional oil producers, including low-decline assets, high free-cash-flow conversion, conservative management, and a margin of safety against mid-cycle WTI prices. The company routinely paid out all of its free cash flow as dividends, and the shares traded at a high dividend yield, so its shareholders could be confident of receiving an attractive return as long as oil prices remained supportive.

I reiterated my bullish view on the shares in April 2025. This time was more of a “pound the table” call with the shares trading at $5. I expected the shares to increase by more than 150% over the next two years. Around that time, instead of buying the stock, I opted for buying Cardinal’s $7.00-strike warrants at $0.44.

By early 2026, events in the Middle East brought the shares within range of fair value. Operational success supported the valuation, as Reford 1 was online and Reford 2 was sanctioned. The stock currently trades at $11.80.

In light of recent developments, Cardinal’s investment thesis needs another update. The company continues to be among my favorites in the Canadian oil patch, and first-quarter results and the Reford 2 sanctioning have changed the calculus underpinning the investment thesis.

Cardinal’s Three-Year Operational Pivot

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(Idea) Borr Drilling - Yikes

By: Jon Costello

Borr Drilling has nearly tripled from its lows, with shares trading at $5.04.

The driver of the stock’s recovery was a year of methodical execution on a highly levered balance sheet.

In July 2025, the company raised $102.5 million of equity at $2.05, with management and the board personally purchasing 22.6% of the offering. It was followed in December 2025 by an oversubscribed issuance of $165 million in 2030 senior secured notes and $84 million in follow-on equity. In April of this year, it refinanced $195.2 million of 2028 convertibles into $300 million of new 3.5% paper due 2033 at a higher conversion price. The move extended the front of the maturity wall while cutting the coupon. All this balance-sheet execution drove the rally in the shares.

To be sure, these measures reduced the risk of imminent bankruptcy and/or equity dilution, which led me to avoid the shares when I last covered Borr in July 2025. They allowed the market to shift its view of Borr from a high-risk refinancing case to a jackup operator in the midst of a cyclical recovery, causing its shares to re-rate.

Borr’s situation has clearly improved, and management should be commended. But the financial and operating recovery has not kept pace with the company’s share price. Dayrates, leverage, and looming debt maturities continue to pose significant risks to shareholders. With these risks in mind, I believe the upside in the shares is less than that of Borr’s deepwater offshore peers. I therefore continue to avoid the name in favor of Transocean (RIG).

The Bull Case for Borr

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Previous write-ups on CLMT 4.64%↑:

Special Situation: Calumet

(Idea) Calumet - The Next Special Situation Idea

(Idea) An Important Update On Calumet

(Idea) Calumet Shares Sell Off Despite A Brightening Outlook

By: Jon Costello

Calumet (CLMT) reported first-quarter 2026 results on May 8, 2026. The results validated my investment thesis. However, they don’t provide the entire story of how the company’s prospects are set to improve, so I want to provide a more comprehensive update.

Since June 2022, my CLMT investment thesis rested on four main assumptions. First, that management would successfully address the company’s debt maturities. Second, that the legacy business would continue to perform as it had in recent years. Third, that management would execute on its operational plan for Montana Renewables (MRL) and the broader business. And fourth, that the policy environment for biofuels would not turn against the company.

All four have now resolved more favorably than I had expected. As a result, the bull scenarios assigned lower probabilities to a year ago are closer to my current valuation, which I discuss below.

In short, recent events have effectively de-risked my CLMT investment thesis, with my new base scenario considerably higher and a bull scenario that is multiples above my old valuation.

Superb Financial Execution

Back in 2022, my articles postulated a bull scenario that required three developments that had not yet happened. As such, they represented a risk for shareholders.

The Montana Renewables project was in its early stages and needed to refinance its expensive legacy debt. MaxSAF 150, the expansion designed to multiply MRL’s sustainable aviation fuel (SAF) output four-to-fivefold, needed to start up on schedule, and CLMT needed to resolve the issue of its high-coupon debt wall, with maturities at the parent level in 2026 and 2027. All three are now done.

The financing piece has been the most significant. On February 18, 2025, the thesis ceased to be conditional. That morning, the first $782 million tranche of CLMT’s $1.44 billion Department of Energy loan guarantee was funded, replacing debt that had cost MRL 9% to 12% in coupon with new debt at roughly 4.9%. Until then, I had held CLMT in the HFIR Energy Income Portfolio for nearly three years. During that time, the refinancing wall the market kept pricing as a real probability of distress. After it was funded, the refinancing wall at MRL was gone.

Equally important, the DOE loan is structured so that if MRL defaults, the lender cannot pursue CLMT. From the parent’s perspective, this is the cleanest piece of leverage MRL has ever carried.

A separate deal at the parent level further eliminated the near-term debt maturity wall. In January and March 2026, CLMT issued $555 million of new 2031 Senior Notes, with the second tranche at 105% of par, a sign that the credit had strengthened between the two issues. It used the proceeds to redeem its remaining 11.00% Notes due 2026 and the 8.125% Notes due 2027. The new coupon is modestly higher than the cost of the retired 2026 and 2027 notes, but the main intention was to extend maturity to ensure catalysts unlock additional value.

The combined effect on recourse leverage, which represents the debt that is an obligation to CLMT itself, not just MRL, was a move from roughly 8x EBITDA to 5x on a forward normalized basis over 2025. Consolidated debt has actually risen because the DOE drawings are layered on top, but the DOE balance does not threaten the parent. The maturity wall was gone.

Stable Legacy Business Performance

Operational improvement at the legacy refining business kept the company’s financial results on an upward trend.

Since 2022, the legacy business has averaged $271 million of Adjusted EBITDA net of Corporate overhead, with a peak of $314 million in 2022 and a trough of $207 million in 2024, when legacy business margins deteriorated due to Shreveport operational issues. EBITDA recovered to $262 million in 2025, and it enters 2026 with the 2:1:1 forward refining margin running at over $42 per barrel against a 2025 average closer to $24. I expect the legacy business to generate relatively healthy EBITDA over the remainder of the year.

Management Executes on Montana Renewables

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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.

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By: Jon Costello

Transocean Q1 2026 Thesis Check-Up

Transocean RIG 2.24%↑ reported first-quarter results on Monday, May 4. Despite its strong performance, its shares declined by 8.3% on the day in response to the news.

Utilization and Dayrates Confirm the Cyclical Component of the Investment Thesis

Transocean’s first quarter provided the cleanest read on operating leverage in years. Total fleet rig utilization reached 86.7% in the first quarter of 2026, up from 63.4% one year earlier and 51.9% three years earlier. A large share of that improvement occurred as the total fleet count fell from 37 units to 27 over the same three-year timeframe. In 2024, the company disposed of three older floaters and, in 2025, six ultra-deepwater drillships. In the first quarter of 2026, it sold the Discoverer India and Deepwater Champion for $27 million in aggregate net cash proceeds. That is the lever the disciplined-contracting thesis called for. A smaller, higher-spec fleet keeps utilization elevated as the cycle progresses, thereby improving the per-rig economics that ultimately flow down to shareholders.

Adjusted EBITDA margin went from 26.9% in the first quarter of 2025 to 40.7% in the first quarter of 2026. In dollar terms, the margin increased by $175 million, indicating that roughly 112% of incremental revenue dropped down to EBITDA.

The trend of higher Adjusted EBITDA margin is another illustration of Transocean’s emerging operating leverage. In the first quarter, the higher margin was driven by 19.3% increase in revenue amid lower costs. Fleet rationalization drove most of the improvement. Some of the revenue increase during the quarter was attributable to revenue being pulled forward, but this does not materially change the picture.

Daily revenue also supports the trend of increasing operating leverage, as the total fleet average daily revenue increased from $443,600 in the year-ago quarter to $475,600 in the first quarter, the highest quarterly average in over a decade, according to CEO Keelan Adamson. Leading-edge contracts are landing at $450,000 per day on the Var Energi (VARRY) contract for the Transocean Barents, in line with the current fleet average.

Additional upside should come from sector tightening rather than catch-up to the leading edge. The operating-leverage payoff is a key part of my Transocean investment thesis, which I outlined in my previous Transocean articles.

Balance Sheet Improvement Ahead of Schedule

Deleveraging is running ahead of schedule. Total debt at quarter-end was $5.137 biillion, down $549 million from $5.686 billion at year-end 2025, and down $1.597 billion from $6.734 billion one year earlier. The major debt transaction in the quarter was the March redemption of the 8.375% Senior Secured Notes due February 2028. Transocean paid $365 million in cash, including the early-redemption premium, to retire the $358 million remaining principal balance, thereby reducing future interest expense by approximately $40 million through maturity. CFO Robert Vayda guided to retiring at least $750 million of total debt in 2026, ending the year with approximately $4.9 billion in principal and trailing net-debt-to-EBITDA of approximately 3.3x. That leverage ratio is well within the 3.5x target management gave for late-2026 on the second-quarter 2025 call.

The Valaris (VAL) transaction will significantly accelerate the deleveraging process two years out. Management is targeting approximately 1.5x leverage within roughly 24 months of close on a pro forma backlog of approximately $12 billion. Cost synergies are guided at more than $200 million, which is incremental to the company’s $250 million cost-reduction program. Two years from now, Transocean’s consolidated leverage profile will approach the kind of investment-grade profile I described in my previous Transocean investment thesis articles.

Backlog, Market Trends, and Benefits of the Valaris Deal

The forward setup is the strongest I have seen over my multiple years of covering the name. Firm contract coverage stands at 86% for 2026 and 73% for 2027, and Chief Commercial Officer Roderick Mackenzie noted that the year-to-date average award duration of 480 days is double the full-year 2025 average. That is a clear signal of a tightening market. Market commentary on the call was markedly more constructive than at any prior point during my coverage. Mackenzie forecasted offshore capex rising from approximately 13% of operator capex toward nearly 30% by 2028 and approaching $100 billion annually by 2030. Adamson stated that he expects deepwater utilization to approach nearly 100% by the end of 2027.

The offshore capex turn I wrote about in my Transocean articles is now showing up in the data. The Valaris combination delivers the structural benefits I described in my February article. Pro forma, Transocean owns 73 rigs, including 33 drillships, which represent roughly one-third of the marketed global drillship fleet. Adding jackup cash flow, geographic reach into the Middle East, North Sea, and Latin America, and a lower cost of capital reduces the odds of another dilutive equity offering.

The wrinkle in the first-quarter report was the news that the U.S. Department of Justice issued a second information request on May 4 in connection with the deal. I suspect this news—which was perceived as negative for the prospects of the deal’s consummation—is what sent the shares lower during the session, which fits the price action better than anything in the operating numbers.

I’m not concerned about the deal’s prospects. I don’t expect the authorities to ultimately stand in the way of this deal. CEO Adamson characterized the second request as “part of the process,” while reaffirming a second-half 2026 close, and noting that prior conversations with the Department of Justice had been “going very well.” The deleveraging path remains intact.

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By: Jon Costello

The oil market is undergoing its largest supply disruption in history. The disruption has opened up an approximately 8.5 million barrels per day (bpd) net supply shortfall in today’s 103 million bpd global oil market.

Looking at stock prices and oil prices in isolation, however, one would never guess at the severity of the supply crisis. In fact, oil and equity markets are behaving as if a rapid resolution is at hand. WTI sits near $102, Brent near $110, with future months trailing downward rapidly in a sequential manner. December Brent futures trade below $80, reflecting roughly $34 of backwardation that prices in near-term normalization. Meanwhile, the S&P 500 is hitting all-time highs regularly.

In my view, both prices are wrong. As long as the supply disruption remains in effect, the historically strong inverse correlation between oil prices and inventories will exert upside pressure on prices; it’s only a matter of time. This outcome has various implications for investors, even as many ignore them.

At a minimum, current oil and stock prices fail to factor in the broader impact this disruption will have on the global economy and, by extension, U.S. corporate earnings and stock prices. Brent sustained above $100 will tax every consuming economy. The earnings of U.S. multinationals, including the megacap technology names that dominate the S&P 500, are exposed to a global growth shock that is not priced in at all. Nevertheless, the longer the outage continues, the higher the oil price will rise, forcing demand curtailment, which increases the risk to corporate earnings and stock prices. For these reasons, I believe investors should adopt a more defensive positioning and remain overweight in the energy sector.

The Disruption: 8.5 Million bpd of Crude is Off the Market

The U.S. and Israel launched their attack on Iran on February 28. In response, the Islamic Revolutionary Guard Corps (IRGC) formally closed the Strait on March 27. Since then, transit through the Strait has been minimal. Kpler data show transit down approximately 92%.

Source: Kpler, April 29, 2026.

S&P Global Market Intelligence has counted just 21 tankers transiting the Strait between February 28 and late April, against more than 100 ships per day before the conflict.

The closure of the Strait and the egress constraint it imposes on Middle East exporters has caused Saudi Arabia, the UAE, Iraq, Kuwait, Iran, and the smaller Gulf producers to shut in a cumulative 11.5 million barrels per day, more than 11 percent of the global oil market. Shut-ins by country are detailed below.

Source: HFI Research, April 20, 2026.

Some supply continues to reach the market through alternative routes, such as Saudi Arabia’s East-West Pipeline to Yanbu, the UAE’s ADCOP pipeline to Fujairah, and Iraq’s Kirkuk-Ceyhan pipeline to the Mediterranean. These workarounds are the means by which the 9.5 million bpd now being produced reaches the market. The volume is significantly less than the pre-conflict production of 21 million bpd, but enough to prevent a complete collapse of Middle East exports.

Strategic Petroleum Reserve (SPR) releases have managed to fill a portion of the supply shortage. The 32-member countries of the International Energy Agency (IEA) agreed on March 11 to a coordinated release of 400 million barrels of strategic reserves, the largest in the agency’s history. The U.S. is contributing 172 million barrels of the sum. Combined releases over the planned 120-day window add roughly 3 million barrels per day to global supply, of which the U.S.’s share is 1.4 million.

Source: IEA. March 19, 2026.

Even with the SPR, the rolling oil supply shortfall stands at a gargantuan 8.5 million bpd. It falls on inventories to absorb this difference. JPMorgan estimates that global observable inventories drew at 7.1 million barrels per day in April, after having drawn 4.0 million in March, for a cumulative draw of roughly 330 million barrels over two months.

As the inventory cushion is eroded, demand reduction will be the next factor to balance the oil market. This is already happening. JP Morgan estimates approximately 4.3 million bpd of forced demand losses in April, mostly in Asian and African importing nations that lack refinery capacity and have run out of fuel regardless of price.

Inventory drawdowns and forced demand destruction have so far done the work of balancing near-term supply and demand. However, the inventory part of that equation is about to run out.

Even the Oil Market Consensus is Too Bearish

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By: Jon Costello

It has been a while since I wrote an update on Cheniere Energy (LNG), which we’ve held in the HFIR Energy Income Portfolio since January 2021. The company recently reached an important milestone and has begun a new phase of growth. How it executes this next phase, as well as prevailing macro natural gas market conditions over the coming years, will have a significant bearing on its stock’s performance.

Cheniere’s track record of execution and strong financial position make it the conservative way to obtain exposure to LNG over the coming years. More than 95% of the company’s production volumes through the mid-2030s are under long-duration sale-and-purchase agreements (SPAs) with a 15-year weighted-average remaining life. Those contracts alone are expected to deliver more than $20 per share of run-rate distributable cash flow (DCF) regardless of where global LNG prices settle. Share repurchases and production growth are set to increase DCF from $20 per share to $30 per share.

Cheniere shares exceeded our published $180 price target in November 2023. DCF growth going forward places fair value at approximately $330.

With Cheniere shares trading at $272, investors who own the name should stay put as management’s execution builds value. They should consider trimming once the shares reach $300, at which point the stock would trade at roughly 90% of fair value.

Investors looking to buy or add to the name should wait for a pullback after the shares’ run from $190 to $272 over the past four months.

20/20 Vision Now Complete

On February 26, 2026, Cheniere completed its 20/20 Vision capital allocation plan. The plan had been announced in September 2022 and served as a framework for allocating the $20 billion in DCF management expected to be generated over the next five years.

Due to consistently outstanding execution, the company completed the plan ahead of schedule. Its forecasted $20 billion in DCF had been generated and allocated to debt repayment, share repurchases, dividends, and growth. It also achieved its targeted DCF run rate of $20 per share.

True to form, Cheniere didn’t rest on its laurels after completing its plan. It immediately launched a new five-year plan that featured an upsized repurchase authorization of $10 billion and a $30-per-share run-rate DCF target on a 175 million share count, implying a 17% lower share count due to repurchases.

I expect this new plan to be completed, and for its completion to drive Cheniere shares to my fair value estimate, which is 21.3% above the current share price.

The 2026-2030 Plan has Begun

Cheniere’s recent financial and operating performance speaks to its ability to achieve its 2030 plan, as it continued to execute superbly on all fronts.

In 2025 alone, the company repaid $652 million of consolidated long-term indebtedness. It repurchased 12.1 million shares for $2.7 billion, including 4.8 million at lower prices in the fourth quarter for $1.0 billion. During the year, it allocated 52% of DCF to share repurchases. Quarterly dividends of $0.555 per share—$2.22 per share annualized—came to $451 million, and growth capex reached $2.6 billion for CCL Stage 3 commissioning.

Looking ahead, the company’s 2026-2030 framework features more of the same capital allocation execution. The board’s $10 billion share repurchase authorization, which is comprised of the $1.2 billion remaining under the previous June 2024 authorization plus an additional $9 billion, represents a more than doubling of potential repurchases, with $9 billion of new capacity versus the prior $4 billion program.

Assuming an average share price of $280, $10 billion of repurchases will retire roughly 36 million shares, bringing the share count from approximately 210 million today to approximately 174 million by 2030. The repurchases increase DCF per share by 21%. Growth projects, namely Sabine Pass Liquefaction (SPL) Expansion and Corpus Christi Liquefaction (CCL) Expansion, would represent DCF upside if they proceed. I expect the repurchases, along with the cash flow generated by the growth projects, to enable the company to achieve its $30-per-share target.

SPAs Provide Cash Flow Stability

Cheniere’s contracted SPAs form the backbone of its investment thesis. According to the company’s latest investment presentation, approximately 95% of total anticipated production from the SPL and CCL projects is contracted through the mid-2030s.

These agreements lock in cash flow through the next decade. The contracted cash flow floor they create is set to deliver more than $20 per share of annual DCF today. The integrity of cash flow is underpinned by creditworthy counterparties, which include investment-grade global buyers such as Shell (SHEL), BP (BP), TotalEnergies (TTE), KOGAS, CPC Corporation, and others. These buyers pay Cheniere fixed take-or-pay fees regardless of whether they lift the cargo.

Meanwhile, non-contracted cargoes capture spot price spreads between global JKM and TTF LNG pricing and domestic U.S. Henry Hub natural gas pricing. Spot exposure adds upside in tight LNG markets and removes upside in weaker markets, but it doesn’t impact the cash flow floor provided by long-term SPAs. If macro conditions in the LNG market push prices higher, spot exposure could accelerate Cheniere’s path toward its $30-per-share DCF target.

Balance Sheet Strength Adds Safety

Liquidity at year-end 2025 was ample, totaling $8.8 billion, including $1.1 billion in cash, $485 million in restricted cash, and $7.2 billion in credit facility availability. Long-term debt stood at $22.5 billion. Sabine Pass Liquefaction retired the full $500 million of its 5.875% 2026 Senior Notes between December 2025 and February 2026.

Net debt increased by roughly $1.5 billion in 2025 as Cheniere drew down cash to fund $2.7 billion in buybacks and $2.6 billion of growth capex. Leverage remained conservative throughout the year. With full-year 2025 Adjusted EBITDA at $6.9 billion versus $6.2 billion in 2024, its net-debt to EBITDA ratio fell modestly, from 3.1x in 2024 to 3.0x in 2025.

The credit rating agencies have a favorable view of Cheniere’s balance sheet. S&P Global Ratings upgraded Cheniere Energy, Inc. and Cheniere Energy Partners (CQP) from BBB to BBB+ with stable outlooks in November 2025. Cheniere Corpus Christi Holdings was upgraded from BBB to BBB+ with a positive outlook in October 2025. The upgrades reflect the company’s enhanced operating quality following the commissioning of CCL Stage 3 and improved cash flow visibility.

Three DCF Scenarios

Cheniere’s 2026-2030 capital plan has clear implications for its stock. The following three scenarios illustrate the potential upside and downside. Each features assumptions pertaining to management’s execution, the macro backdrop, and the company’s financial performance.

The contracted long-term SPAs provide a cash flow base. Changes from the base depend to a significant degree on marketing activities conducted by Cheniere Marketing International (CMI), Cheniere’s in-house marketing and trading arm. CMI sells uncontracted LNG volumes into the spot and short-term markets, capturing the spread between Henry Hub feedstock prices and international LNG prices.

My base scenario follows management’s guidance, with CMI’s margin at $2.50 per MMBtu, both SPL and CCL Expansion final investment decisions (FIDs) by 2027, and full deployment of $10 billion. The bear scenario shrinks CMI’s margin to $1.50 per MMBtu, defers both Expansion FIDs past 2030, and deploys only $5 billion of the $10 billion buyback. The bull scenario maintains the same FID assumption, increases CMI’s margin to $3.00 per MMBtu, and accelerates repurchases to 2028.

The base scenario, at an 11x DCF multiple, supports a share price of $330. I expect such a scenario to provide long-term holders of the name an opportunity to exit at a higher price.

The bull scenario at an 11x DCF multiple implies a price of $363, for 33.5% upside. A more conservative bull scenario using a 9x multiple implies a price of $297, 9.2% above the current price and just below my planned trim level.

A bear scenario at an 11x DCF multiple supports $264, 3% below the current price. However, a more severe bear scenario using a 9x multiple supports a $216 share price, representing 20.6% downside. The stock price declines in this scenario due to multiple compression, as DCF per share is roughly flat with 2026.

The table below walks through the bear scenario math, the most adverse of the three scenarios.

Risk-reward at $272 features 21.3% upside, with downside ranging from negligible at flat multiple to material at full margin compression.

Applying analogous bridges for the base and bull scenarios produces the DCF per-share figures shown in the scenario table below.

At $272, the call is to hold. My base scenario puts fair value at $330, implying roughly 21% of upside that share buybacks should help deliver over the next 18 to 24 months. Current holders of the shares should consider trimming at $300, or at roughly 90% of fair value, taking, say, 20% to 30% of their position off the table, and accelerate trimming above $325, where the stock would already reflect near-perfect operational and financial performance. However, I wouldn’t be likely to exit the shares completely at any level, as Cheniere’s contracted cash flows and ongoing buybacks should continue to grow per-share value over a five-year period, and perhaps beyond.

For investors looking to add to their position, consider entering around $240. At that level, Cheniere trades at approximately 11x current run-rate DCF and 8x the $30 DCF target. This multiple would be at the low end of the historical range for high-quality contracted midstream operators. The $216 price in the bear scenario at a 9x multiple is 10% below $240, while the $330 price in the base scenario is 37% above. That 4-to-1 upside-to-downside is the kind of setup that I believe justifies adding in size rather than nibbling.

Downside Risk

Given all the operational and macro-level risks in the outlook, it is important to consider the various ways my fair value estimate can fall short. Four bearish variables, in particular, could cause Cheniere shares to undershoot my estimates in the scenarios above.

The first variable is multiple compression. At $272 per share, Cheniere trades at roughly 12.5x its full-year 2026 guidance midpoint DCF of approximately $21.90 per share ($4.6 billion ÷ 210 million shares). High-quality, contract-protected midstream peers trade at DCF and EBITDA multiples in the 8x to 11x range. Cheniere’s 15-year weighted-average remaining life on its SPAs and its relatively high return on capital support a multiple at the high end of the range. Still, company-specific or sector-wide multiple compression would provide a headwind for the share price.

The second bearish variable relates to Cheniere’s post-2030 SPA roll-off schedule. The company does not disclose details other than the 15-year weighted-average life of its contracts. However, this statistic suggests the company is exposed to repricing risk as contracts renew after 2030. If contracts roll off in a softer global LNG market, both fixed-fee renewals and CMI margins are at risk of repricing downward.

A subtle disclosure trend in the 2025 10-K reinforces roll-off risk. Cheniere states in its 2025 10-K that approximately 90% of total anticipated production from the SPL and CCL projects is contracted through the mid-2030s. This is down from 95% in the 2024 10-K. The likely explanation for the decline is that the 10-K denominator reflects in-construction CCL Stage 3 capacity for which long-term SPAs have not yet been signed. As growth capex delivers new production volumes, this percentage could drift lower until expansion-related SPAs catch up. The bull scenario on Cheniere therefore depends in part on management’s ability to commercialize SPL Expansion and CCL Expansion volumes ahead of the early-2030s roll-off, execution that has been strong but cannot be guaranteed.

However, I’m not overly concerned about roll-offs in Cheniere’s case. For one, recent contract signings point to upside, not downside, on the pricing front. Cheniere’s long-term deals with Galp (GLPEY), Equinor (EQNR), Foran Energy, and others, signed between 2022 and 2025, locked in higher fixed fees than the older contracts they replaced. As a result, the portfolio’s average pricing is increasing, not declining. The bearish premise assumes a deterioration that these contract wins appear to contradict.

Furthermore, Cheniere’s main competitor is potentially in trouble. Venture Global (VG) is in arbitration with BP, Shell, and other major customers over cargoes VG diverted to spot markets instead of delivering to its customers under contract. The damages claimed run into the billions, and the situation poses financial risks for VG while also diminishing its standing as a reliable supplier. After VG’s actions, I suspect LNG buyers looking to lock in post-2030 volumes will be willing to pay a premium for proven operating and delivery records. Cheniere has an impeccable track record in both areas, which should result in higher fixed fees in new SPAs.

Lastly, the math holds in the moderate bear scenario. Even after applying the bear adjustments shown in the bridge above—CMI margin compression, spot-pricing weakness, and a fixed-fee discount on early-vintage SPA renewals—DCF lands at $24 per share. At a 9x multiple, which is low for contracted infrastructure operators, the shares would trade at $216, or 21% below today’s $272. Meanwhile, the base scenario produces $330 at 11x, or 21% above the current price.

That said, Cheniere investors should know that the moderate bear scenario detailed above isn’t the potentially deepest downside. An extremely bearish scenario, in which the CMI margin declines to $1.00 per MMBtu in a structurally oversupplied 2027-2028 market, $5 to $7 billion of repurchase capacity is redirected to growth capex, the CCL Stage 3 ramp is delayed by six to nine months, and SPAs are renegotiated at, say, 15% below current fees, reduces DCF to $18 to $20 per share. At an 8x multiple, the implied price is $144 to $160, or a 41% to 47% decline.

While I think it’s highly unlikely that all these stressors occur simultaneously, it’s not entirely implausible, particularly amid severe global economic deterioration. Still, the moderate bear remains my central downside scenario and is part of the reason why I’ll consider trimming above $300.

The third variable that would cause Cheniere shares to undershoot my fair value estimate is the timing of the SPL Expansion FID. The project’s FERC application and DOE non-FTA application remain pending. A 12- to 24-month completion slip puts $4 to $6 per share of DCF at risk, which is the mid-decade catalyst for a bullish outcome.

A fourth bearish variable is a sustained rise in U.S. natural gas prices. Cheniere is largely insulated on its long-term contracts because customers pay the gas cost as a pass-through, but sustainably higher Henry Hub prices, which natural gas bulls believe will be driven by data center demand, home heating recovery, and LNG export growth, could reduce earnings on spot-market sales by $50 to $150 million annually and, more importantly, make new U.S. LNG contracts less competitive against lower-cost global supply, such as that produced by Qatar. Those new contracts are what the bull case depends on to fund expansion.

Beyond the four bearish variables above, four specific developments would cause me to consider trimming or selling Cheniere shares more aggressively. If the company were to repurchase less than $2 billion of stock in 2026, the path to a 175-million-share count would extend longer, and management’s commitment to its buyback pace would come into question. If Cheniere signs a new long-term SPA at $2.00 per MMBtu or below—which would be roughly 25% below current pricing—it would signal that the prices the company can lock in for contracts rolling off after 2030 are lower than the bull case assumes. If the completion date of CCL Stage 3 Trains 5-7 slips past March 2027, the company’s 2027 EBITDA would be at risk of declining below my estimate. And if regulators delay an authorization of the next major expansion past year-end 2027, 20 MTPA of growth gets pushed into the early-to-mid 2030s. Any one of these outcomes alone would dim my view of the company’s prospects. Two or more would prompt me to consider selling.

Conclusion

Cheniere is the conservative way to own LNG. The contracted floor delivers more than $20 per share of run-rate DCF today, and the buyback math drives DCF per share to roughly $30 by 2030. At $272, investors should consider holding and potentially trimming above $300.

We entered Cheniere on January 25, 2021, at $63.82 in our HFIR Energy Income Portfolio. Our position has generated a 334.6% total return and now stands at a 6.0% weighting in the portfolio. Outstanding execution in operations, deleveraging, distributing capital to shareholders, and a strong contracted cash flow floor drove our gains. I expect the same factors to continue sending the shares to $300. At that point, depending on the macro backdrop, I’ll consider trimming my position and holding the rest as the framework continues to work.

Link to HFIR Energy Income Portfolio on RunPlutus.

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

By: Jon Costello

Venture Global is one of three large publicly-traded U.S. LNG companies. Its peers are Cheniere Energy , the operator of Sabine Pass and Corpus Christi export facilities, and NextDecade , a development-phase company set to begin exports in 2027 from its Rio Grande LNG facility. Among U.S. LNG exporters, only Cheniere and VG currently produce at commercial scale.

VG owns two liquefaction facilities on the Louisiana Gulf Coast: Calcasieu Pass, which declared commercial operations in April 2025, and Plaquemines, which is currently in commissioning. Plaquemines Phase 1 is expected to reach commercial operations in the fourth quarter of 2026 and Phase 2 in mid-2027. The company has a third facility, CP2, a $33 billion greenfield project that received final investment decision (FID) in July 2025, is under construction, and expected to commence LNG production in late 2027. Beyond these, VG has expansion projects at both Plaquemines and CP2, as well as a separate greenfield project, CP3, in early development.

VG’s competitive edge is its construction speed and modular cost discipline. Rather than using two or three large liquefaction trains as older U.S. projects did, VG uses dozens of smaller, factory-built mid-scale trains that can be installed sequentially. Its first facility, Calcasieu Pass (CP1), went from FID to first cargo in roughly 30 months, a timeline the company bills as the fastest FID-to-first-cargo for a greenfield U.S. LNG project.

VG also owns a fleet of seven LNG tankers with two more on order, bringing the total fleet to nine. This lets the company ship its own cargoes to wherever in the world LNG prices are highest. Most of its U.S. peers sell at the Gulf Coast dock and let the buyer profit from shipping the LNG overseas. To the extent VG’s facilities produce more LNG than their contracted nameplate capacity, the company can use its own tanker fleet to capture spot prices on those excess volumes.

CP1 is currently producing at roughly 11.2 million tons per annum (mtpa), about 12% above its 10 mtpa nameplate capacity, thanks to the same modular design that enabled fast construction. As Plaquemines completes commissioning, VG’s consolidated output will climb to approximately 40 mtpa by the time both of its phases reach commercial operations. The table below summarizes VG’s full project portfolio.

Investors should avoid VG shares at the current price. My concerns center on three areas: the company’s deteriorating margin economics, its slow-to-deleverage balance sheet, and management practices that, in my view, put minority shareholders at risk. The sections that follow walk through each in turn.

From an economics perspective, revenue tied to spot pricing will wind down as contracted SPAs replace it, compressing margins even as total LNG production volumes rise. The balance sheet is an issue because leverage peaks in 2026, and only the bull-case EBITDA scenario fully deleverages the company back toward 2025 levels by 2028. And management’s conduct toward VG’s contracted counterparties and IPO disclosure practices raises questions about how this team is likely to treat minority shareholders when their interests diverge from its own.

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By: Jon Costello

• The HFIR Energy Income strategy, now managed on the Plutus platform, has delivered a gross return of +278% since December 2020.

• The strategy applies the investment approach I have practiced and published publicly since December 2020.

• Portfolio construction emphasizes free cash flow growth, low turnover, and disciplined position sizing across the energy value chain, prioritizing long-term free cash flow growth and compounding over headline yield.

Energy income is still cheap. Midstream multiples sit in the high single digits to low double digits on EV/EBITDA, dividend yields across the income complex exceed 5%, dividend payouts are growing, and sector balance sheets are in the strongest shape they have been in fifteen years. That combination is rare in today’s U.S. equity market.

Given the opportunities we see and our track record of outperformance, we are now publishing our portfolio on the Plutus platform. Plutus connects individual investors with curated and thematic model portfolios from independent professional investment research managers. Its system allows an investor to replicate the researcher’s portfolio in their own investment account.

Through Plutus, investors can now access the HFIR Energy Income strategy. I will apply the same investment approach that I have practiced and published since we launched the strategy in December 2020. The portfolio structure, selection criteria, and emphasis on free cash flow growth carry over directly from what I have done on Seeking Alpha for more than five years. The approach has not changed.

Plutus Applies a Philosophy I Have Practiced Publicly for Five Years

My energy income investment philosophy has been public since the inception of the Energy Income portfolio. It is spelled out in this article, which was published when we launched the portfolio. Neither the article nor my approach to managing the portfolio has changed since then, which is borne out by the portfolio’s metrics. My approach is to buy equity in understandable businesses at discounts to conservative estimates of intrinsic value and hold for two to five years. I hold 10 to 20 names, concentrated around three or four ballast positions bought cheaply. I benchmark against the S&P 500 and treat outperformance as the best gauge of a manager’s skill, and I consider risk to stem from permanent capital loss, not paper drawdowns.

Outside of my five-year history with the HFIR Energy Income public tracking portfolio, my career spans 19 years. I have managed money independently and full-time since 2007, beginning as a generalist value investor across multiple sectors. Since 2016, I’ve been concentrated in energy, which has been my primary focus area since. Across both periods, I have managed portfolios for income and capital appreciation on my own platforms outside of HFIR. The HFIR Energy Income portfolio was launched at the end of 2020.

Returns

The HFIR Energy Income portfolio is a hypothetical model portfolio. Every buy, sell, add, and trim has been published on Seeking Alpha in real time since the portfolio’s inception on December 14, 2020. The tracker calculates what a subscriber would have earned by executing those decisions at published prices, gross of fees and taxes.

The HFIR Energy Income strategy has outperformed by a wide margin. The table below compares the gross record against two standard benchmarks.

Source: Internal analysis of HFIR Energy Income trade ledger, December 14, 2020, through April 7, 2026. Benchmark return series derived from Yahoo Finance adjusted close (total-return-equivalent).

The aggregate number hides year-to-year dispersion. The table below shows calendar-year total returns since inception.

Source: Internal analysis of HFIR trade ledger. 2020 return spans December 14 through December 31, 2020 (17 days). 2026 YTD return spans January 1 through April 7, 2026 (partial year). All other years are full calendar years. Returns are gross total return (price appreciation plus distributions received).

No full calendar year has produced a loss. The only negative figure is the 17-day partial in December 2020. Dispersion across full years runs from +14.18% in 2025 to +35.98% in 2022, with 2024 adding a second-best +33.94% to the record. In 2023 and 2025, returns were in the low-to-mid teens, above the S&P 500’s long-run average, but worth noting as the periods when the strategy did not outperform the benchmark.

Cumulative dividends and distributions received total approximately $526,000 against a $1 million starting capital base.

The past hypothetical performance of the HFIR Energy Income portfolio is not predictive of future actual results. Also, the gross-of-fees performance figures overstate what a real-money investor would have earned. The numbers are directional evidence of a philosophy at work, not a guarantee of what our Plutus portfolio will deliver.

Free Cash Flow Growth Is the Real Guarantor of Income Safety

Most energy income portfolios optimize for a headline income yield in the here-and-now. However, I’d argue that the sustainability of an income stream is determined not by its current yield but by the underlying business’s ability to generate free cash flow and to grow and distribute that cash flow over time.

Consider the mechanics. A business with flat or declining free cash flow that pays out most of what it produces will eventually cut its dividend or weaken its balance sheet to maintain it. A business with growing free cash flow can safely raise its dividend and fund reinvestment, while protecting its balance sheet. Income safety is therefore a byproduct of operational and financial strength, not simply a product of payout ratios or yield levels.

Over time, growing free cash flow drives higher dividends. Higher dividends, in turn, lead to a higher stock price as the price increases to maintain the stock’s yield. Meanwhile, free cash flow growth can lead to a multiple re-rating.

The upshot of the HFIR Energy Income strategy of prioritizing free cash flow growth is that the portfolio has generated roughly four times more return from capital appreciation (+226%) than from income received (+53%). That ratio surprises investors who assume an income portfolio should be primarily an income story. It is not. It is a quality-compounding story that pays a dividend along the way.

One implication of this strategy is that our Plutus portfolio will likely have a lower current yield than peer energy-income portfolios that optimize for present-day cash generation. This is partly a result of our portfolio having purchased equities at lower prices when their dividend yields were significantly lower and holding them as their dividends and market prices increase. I would rather hold a position yielding 5% today whose distributable cash flow grows 10% annually than one yielding 8% today whose distributable cash flow is flat or falling. Over a full cycle, the former position benefits from receiving both income and attractive total returns.

Plutus Spans the Entire Energy Value Chain

In the energy sector, relative value rotates across sub-sectors. Across the HFIR Energy Income portfolio’s 77 trades to date, it has owned names in upstream E&P, gathering and long-haul pipelines, refining and specialty chemicals, LNG export, and royalty and mineral streams, in both U.S. and Canadian operators. Restricting the mandate to any single sub-sector would cost performance over a full cycle.

Our Plutus portfolio is built on the same principle. As of April 1, 2026, the equity book broke down as follows.

Source: Plutus portfolio weightings as of April 1, 2026; percentages expressed as share of the 90.3% equity component (excludes 9.7% SGOV allocation).

The portfolio has 15 equity positions. A small cluster of top names serve as ballast; the remainder are rotating conviction positions. The structure matches my longstanding concentrated value investment philosophy.

Low Turnover Boosts Returns

Patience pays over the long term. The HFIR Energy Income portfolio has executed 77 trades over approximately 5.3 years, or roughly 14.5 trades per year, across a portfolio that typically runs ten to twenty names. The annualized turnover ratio sits at 16.9%, and the cost-weighted average holding period is 2.18 years. That falls within my stated two-to-five-year target and demonstrates that I am holding positions long enough for the thesis to work without being married to them.

The table below summarizes the turnover profile.

Metric

Source: Internal analysis of HFIR trade ledger, December 14, 2020, through April 7, 2026. Annualized turnover ratio = the lesser of buy/sell volume per year, divided by average portfolio value.

Low turnover matters for three reasons. It keeps transaction costs down across a full cycle. It signals that position sizing was conviction-led, not reactive. And it reduces the churn that degrades after-tax returns in taxable accounts. The Plutus portfolio will be run with the same discipline.

The Treasury Bill Component Reflects Discipline, Not a Hedge

The portfolio holds a 9.7% position in Treasury bills through SGOV, a short-duration U.S. Treasury ETF. This holding is deliberate but does not reflect a market-timing posture. Energy is structurally volatile, and volatility creates the entry points that drive a value investor’s returns. Maintaining a liquid, low-risk component of the portfolio will allow me to deploy into dislocations as they appear, without being forced to sell existing positions at the wrong time.

The HFIR Energy Income portfolio has been building an opportunistic cash position since 2025 by retaining income from dividends and distributions. In an environment of elevated sector volatility and with a selective pipeline of opportunities, the buffer is the right posture. I expect to deploy all of the portfolio’s cash when opportunities become sufficiently attractive.

Risks

• Commodity prices. A sustained collapse in oil and gas prices reduces free cash flow for several of the portfolio’s holdings. Midstream and LNG exposure provides a buffer, but does not eliminate this risk.

• Dividend or distribution cuts at specific holdings. The concentrated nature of the portfolio’s holdings means a dividend cut at a top position would affect the portfolio’s yield and/or dividend growth.

• Policy risk. U.S. energy policy has become more volatile in 2025 and 2026. Permit delays, pipeline cancellations, and LNG export restrictions could affect specific names.

• Tax implications. Each investor must manage their income investments according to their own tax situation. Income-producing securities generate ordinary income, qualified dividends, K-1 pass-through income, and return-of-capital distributions, each of which is taxed differently. MLPs held in retirement accounts can trigger UBTI; Canadian holdings are subject to withholding. Mismatched account placement can lead to unwanted tax consequences.

• Canadian exposure. Whitecap Resources, Cenovus Energy, Suncor Energy, Strathcona Resources, and ARC Resources carry Canadian-dollar exposure and WCS-WTI differential risk. Historically a source of alpha, it can turn into a drag if differentials widen.

Disclosures and Terms

Our Plutus Energy Income model portfolio carries a 1% annual management fee and no performance fee. The HFIR Energy Income portfolio’s returns cited above do not reflect any management fee. Applying a 1% annual fee would reduce the compounded return. Prospective investors in Plutus should evaluate net-of-fee projections.

We have a compensated relationship with Plutus. This article is published under our Seeking Alpha byline as an educational piece on investment philosophy and portfolio construction. It is not an offer to sell or a solicitation of an offer to buy any security. Investment decisions regarding Plutus should be made based on the fund’s official offering documents and after consultation with qualified legal, tax, and financial advisors. MLP investments carry specific tax considerations, including Schedule K-1 filings and potential UBTI implications in retirement accounts, which may affect suitability for individual investors.

Conclusion

The investment thesis that underpins our energy income portfolio is durable. Energy income securities still offer yields in excess of most other cash-flowing assets in U.S. public markets, the underlying businesses are financially stronger than they have been over the last fifteen years, and LNG, gas, and midstream demand continue to expand. The philosophy I have practiced for the past five years has produced a hypothetical return of 278% against the S&P 500’s 95% over the same period. Plutus applies that discipline to real capital.

I believe the strategy will continue to compound. I am using Plutus to provide access to investors who cannot or prefer not to manage a 15-name energy portfolio themselves. Investors interested in modeling the HFIR Energy Income approach should visit the Plutus site for more information.

Analyst’s Disclosure: Jon Costello has a beneficial long position in the shares of the HFIR Energy Income Portfolio and the HFIR Energy Income Plutus Portfolio either through stock ownership, options, or other derivatives.

By: Jon Costello

Please see the previous write-up on Genesis Energy.

Genesis Energy, LP has quietly transformed itself over the past 18 months. The company sold its soda ash business for $1.425 billion, used the proceeds to dramatically clean up its balance sheet, and is now a focused Gulf of America pipeline company with two transformational deepwater projects ramping into full production. At $17.60 per unit, GEL trades on a 4.1% yield with trailing EBITDA of $544 million and 15–20% guided growth into 2026. Distribution coverage sits at 2.77x. The market is still pricing GEL units as a leveraged turnaround, but the inflection has already happened, as I have discussed in previous articles.

GEL is one of the more attractive risk-reward setups in midstream today. The company controls critical infrastructure that every deepwater Gulf of America producer depends on, and the market is still anchored to an old narrative regarding leverage and complexity that no longer applies. While the unit price is up 37% over the past twelve months, it remains well below its pre-pandemic levels, implying the re-rating is underway but far from complete. Analysts target $19.33. I think intrinsic value is meaningfully higher.

GEL’s High-Quality Assets

Post-divestiture, GEL operates three segments: Offshore Pipeline Transportation, Marine Transportation, and Onshore Transportation Services. The offshore network spans roughly 1,400 miles of crude oil pipeline and 764 miles of natural gas pipeline in the Gulf of America. Key assets include its 64% owned Cameron Highway Oil Pipeline System, or “CHOPS,” which spans some 400 miles with more than 700,000 barrels per day (bpd) of design capacity, its 64% owned Poseidon system in the central and western Gulf, its 29% owned Odyssey system in the eastern Gulf, and its 100% owned SYNC system, which spans 105 miles and is dedicated to the Walker Ridge area and Shenandoah. GEL’s revenue is tariff-based on life-of-lease dedications with long-term contracts. Less than 5% of its gross margin is derived from take-or-pay minimums, as its customers actively use its pipelines, indicating its assets are competitively positioned.

What makes GEL special is that it’s the only independent crude oil pipeline operator in the Gulf of America. Shell (SHEL) and BP (BP), the two largest producers in the Gulf, are integrated operators, which creates inherent conflicts. For instance, when Shell owns a pipeline and also produces the crude that flows through it, the third-party producer shipping on that same system knows they’re not the priority customer. Since GEL has no upstream production, its incentive is purely commercial, namely, to maximize throughput at competitive tariff rates. That independence serves as a structural moat, which becomes more valuable in exactly the kind of tight supply environment we’re in now.

The Balance Sheet Transformation

In February 2025, GEL closed the sale of its soda ash operations to WE Soda for $1.43 billion gross and $1.01 billion net. The company immediately paid down its $800 million revolver, redeemed $406 million of 8.0% senior notes due 2027, and repurchased $250 million of preferred units. Annual capital cost reduction: over $120 million. This was GEL trading a cyclical commodity business for balance sheet freedom at exactly the right time.

Since then, GEL has continued cleaning house. It issued $750 million of 6.75% notes due 2034, replacing 7.75% notes due 2028 and saving $12 million in cash interest per year while extending the maturity wall by 6 years. The credit facility was extended to 2031 and expanded to $900 million.

In March 2026, the company repurchased another $110 million of its preferred units at 102% of par. The upshot is that the company has no material debt maturities until early 2029, a minimal revolver balance, and bank leverage of 5.12x, which is poised to compress as EBITDA grows. At a 15% to 20% EBITDA growth rate, the math gets GEL to sub-4.5x leverage by late 2026 without any additional asset sales. That is an investment-grade trajectory.

Shenandoah And Salamanca Change Everything

The core of GEL’s bull case is that the Shenandoah oil production platform, a 120,000 bpd deepwater platform expandable to 140,000 bpd, delivered first oil in July 2025 and reached 100,000 bpd within 75 days from just four Phase 1 wells. It accomplished this feat more quickly than industry consensus expected. Shenandoah’s output connects directly into GEL’s 100%-owned SYNC pipeline. Meanwhile, the Salamanca oil production platform adds another 50,000 bpd of nameplate capacity, with first oil in September 2025 and three wells currently ramping toward 40,000 bpd. Together, these projects are expected to generate approximately $150M in incremental annual segment margin once at full production, representing a 27% uplift to the company’s baseline EBITDA. This is not a projection. It is occurring right now.

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I’ve been thinking a lot about how to position and when—or even if—to sell oil-related holdings after their surge in response to the conflict in Iran. Aside from investing a portion of the distributions received, the HFIR Energy Income Portfolio has had no trading activity over the past 15 months. But its daily performance looks like this:

I’d be crazy not to consider trimming after such a rapid surge in the portfolio. The trick, as always, lies in the timing.

Physical Fundamentals Justify the Premium

Since the U.S.-Israeli strikes on Iranian nuclear and military infrastructure began on February 28, Brent crude has surged from roughly $80 per barrel to over $112, or more than 50% in a single month. On Monday, March 30, WTI settled above $100 for the first time since July 2022. The IEA and other experts have characterized the disruption to flows through the Strait of Hormuz as the largest supply disruption in the history of the global oil market.

The risk premium on crude oil is no longer based mostly on market anticipation. Iran’s Islamic Revolutionary Guard Corps closed the Strait to most commercial shipping on March 4. A selective reopening on March 26 now permits transit for ships flagged to five nations, namely China, Russia, India, Iraq, and Pakistan, but the net reduction in flows is estimated at roughly 11 million barrels per day. For context, that strait normally handles approximately 21 million barrels per day, or about 20% of global petroleum liquids consumption.

Energy equities have followed the surge in oil. The XLE is up approximately 40% year-to-date through March, outperforming the S&P 500 by over 32 percentage points. This is the widest gap ever recorded in a single quarter. Fourteen of the 22 XLE constituents rallied more than 10% in March alone.

The instinctive conclusion is straightforward: higher oil prices justify higher equity valuations, and the disruption is real this time. But looking at history, I’m more inclined to believe that some de-risking may be in order.

The Pattern That Repeats: War Premiums Collapse

The risk, as I see it, for holders of energy equities arises due to the historical pattern of collapsing risk premiums once supply risks fade. The pattern is for oil prices to peak at maximum uncertainty, not necessarily maximum disruption. Prices then collapse once markets realize the worst-case scenario either will not materialize or has already been priced in.

Historical analogs follow a similar pattern.

Gulf War, from 1990 to 1991. Iraq’s invasion of Kuwait drove oil prices sharply higher as markets priced in a prolonged supply shock. Once it became clear that a U.S.-led coalition would restore flows, oil collapsed before the conflict itself had fully resolved. The peak occurred when fear was highest, not when fundamentals were most impaired.

Libya in 2011. The civil war removed roughly 1.5 million barrels per day from global supply. This was an actual, physical disruption, and prices spiked accordingly. Yet Saudi spare capacity and global supply adjustments filled the gap faster than expected, and the rally faded.

Russia-Ukraine in 2022. This is perhaps the most relevant recent analog prior to today. Oil surged above $120 per barrel amid fears of massive, sustained supply losses from one of the world’s largest exporters. Those fears proved to be dramatically overstated. Russian barrels were rerouted, demand adjusted, and oil prices declined even as the war continued. Markets consistently overestimated the persistence of disruption.

These episodes reflect a structural feature of the oil market. Markets tend to discount probabilities. The oil market has tended to embed worst-case scenarios into prices early on, leaving limited room for further upside. Historically, supply has generally been more flexible than assumed, adjusting to disruptions through spare capacity, inventory drawdowns, and rerouting. Meanwhile, higher prices reduce consumption, particularly in emerging markets, while speculative positioning amplifies both the rally and the inevitable unwind.

In all these previous episodes, the geopolitical risk premium was not a stable component of oil prices. It was a temporary overlay that disappeared abruptly once uncertainty abated.

This Episode Breaks the Historical Mold

Today’s disruption differs from previous episodes in important ways, with important implications for portfolio positioning.

First, this is a chokepoint disruption, not a producer outage. Past disruptions, such as those involving supply losses in Libya, Iraq, and even Russia, also led to production losses. In those situations, the global system had enough spare capacity to offset the production losses.

By contrast, the Strait of Hormuz is a transit artery. Disruption here affects flow, not just supply, and rerouting is far more complex. There is no pipeline bypass for 21 million barrels per day of seaborne crude, condensate, and refined products.

Second, the disruption has actually materialized. In previous episodes, markets priced for a disruption that never fully occurred. Here, the Strait was physically closed for weeks, and the selective reopening excludes most Western-allied shipping. The 11 million barrels per day net reduction dwarfs the scale of previous disruptions. This is not a risk premium on a theoretical anticipated threat, but a premium on an ongoing event.

Third, the system’s shock absorbers are weaker. Before this disruption, OPEC’s deployable spare capacity stood at 1.5 to 2.5 million barrels per day. This spare capacity was concentrated almost entirely in Saudi Arabia and the UAE. This spare capacity represents a fraction of the volumes currently disrupted. More importantly, the strategic value of this spare capacity is diminished when low-cost drones can credibly threaten the infrastructure that produces it. The vulnerability of concentrated spare capacity in the Middle East to military threats is a structural shift the market has not fully priced in.

Consider further that U.S. shale production has plateaued at roughly 12.7 million barrels per day over the past several months. Capital discipline, depleting Tier-1 acreage, and muted drilling response mean the U.S. is no longer the swing supplier it was in the 2014 to 2019 timeframe. In fact, the EIA is forecasting a slight decline in U.S. output in 2026.

Fourth, escalation risk is nonlinear. Previous conflicts were localized events. By contrast, today’s situation involves direct military strikes on a major regional power, the killing of its leadership, and retaliatory missile and drone strikes on U.S. bases and allied Gulf states. Diplomatic efforts have thus far failed, with Iran rejecting a U.S. 15-point proposal on March 25 and its parliament stating it will not negotiate under coercion. The pathway from here includes infrastructure targeting, further shipping disruptions, and broader regional spillover.

Fifth, normalization takes longer than the market assumes. Even in a peace scenario, the physical process of restoring transit through the Hormuz Strait will be measured in months, not days. Empty vessels need to be repositioned into the Strait and then routed back to destination points. Safety buffers, such as unsanctioned oil-on-water and SPR draws, are being exhausted. Cumulative Middle Eastern production losses are projected to reach as much as 1 billion barrels even under an optimistic mid-April normalization, effectively killing the surplus narrative that had characterized pre-crisis balances. And restarting production from shut-in fields takes months. For instance, Kuwait has publicly stated that it expects its own fields to take 3 to 4 months to fully resume operations. Restarting production from less technologically sophisticated fields carries the risk of damaging reservoirs after a prolonged shutdown. Clearly, this massive global system of mindboggling complexity will not straighten itself out overnight.

Resolving the Tension: What the Outcomes Look Like

This is where I think investors risk making the wrong call. In moments of fear and uncertainty, there is a temptation to focus on binary outcomes and make binary trading decisions. Investors may opt to either stay fully invested, betting on continued escalation, or exit entirely, betting on historical precedent. Both approaches ignore the wider distribution of potential outcomes.

At the moment, several such outcomes strike me as likely.

Scenario A: Negotiated de-escalation within 60 to 90 days (40% to 50% probability). A diplomatic resolution or a sustained ceasefire leads to the reopening of the Strait. In this scenario, I would expect oil to decline, but not to pre-crisis levels. Even during de-escalation, the normalization of physical flows will take months, cumulative supply losses will have reset global balances, and an enduring political risk premium of $10 to $20 per barrel will likely persist in light of the Strait’s demonstrated vulnerability. Given all the factors at play to date, I expect Brent in the $80 to $90 per barrel range. At those prices, energy equities would give back a portion of their first-quarter gains but would find support above pre-crisis levels. This remains the most likely single outcome, but I’ve reduced its probability from my initial estimate because the normalization timeline alone, which includes months of vessel repositioning, field restarts, and stock rebuilding, will make a clean, rapid unwind unrealistic.

Scenario B: Prolonged partial disruption (35% to 45% probability). The selective reopening of the Strait persists. Some barrels flow, but at a higher cost and with insurance premiums. Oil stabilizes above $100 per barrel and at times heads toward $120 for several quarters. In this scenario, the likelihood of broader economic damage from the outage increases. Markets and stock prices would discount a weakening economy. Energy equities would likely hold their gains and trade sideways. This is the scenario markets are increasingly pricing in, and the one whose probability I’ve revised upward. The structural factors in play all support a more persistent disruption than historical analogs would suggest.

Scenario C: Full escalation and sustained closure (10% to 20% probability). The conflict widens, infrastructure is targeted, and the Strait returns to full closure. Oil is sustained above $130, which is the price at which I estimate demand curtailment will begin on a broader scale in more developed economies, which consume most of the world’s oil. Energy equities re-rate further before the global economy buckles under the strain of higher energy prices, at which point they would decline from their highs. This scenario represents the tail risk.

What to Do: Reduce Position Size, Not Exposure

The appropriate response is not to exit all energy investments in full. It is to de-risk while maintaining meaningful exposure. The key point is that, despite the structural arguments for a higher floor, current prices still reflect a premium that is at risk of rapidly diminishing. The historical pattern of overshoot remains intact, even if the downside in the current situation is less extreme.

I would recommend trimming overall energy equity exposure by approximately 10% to 15% at current levels. This is not a defensive retreat, but a recognition that the market is pricing a sustained disruption with limited margin for error. The objective is to reduce exposure to a potential normalization of the risk premium while retaining long-term participation in a structurally tighter market.

For energy specialists, holding cash seems prudent. I have already raised the HFIR Energy Income Portfolio’s cash position to 4%, and I’m considering increasing it to the 15% to 20% range. This cash can be deployed back into the energy sector in the event commodity and/or stock prices decline. Alternatively, it can be deployed more widely into other sectors if oil prices run away to the upside and the rest of the market declines.

What to Trim First

After deciding to de-risk, an investor must determine what to sell first. I would focus on names with the highest beta to spot oil prices. These stocks have rallied most aggressively and carry the most downside if oil corrects.

The first candidates for trimming are lower-quality E&Ps with high oil torque. Devon Energy (DVN) and APA Corporation (APA) are two such examples that come to mind. These are widely held stocks that have led the XLE, with a 44% gain in March alone. They are currently among the E&Ps most exposed to a risk premium unwind. These stocks have re-rated on pricing that may not persist.

Second, I would consider lightening up on integrated majors that have benefited from multiple expansion. Exxon Mobil (XOM) and Chevron (CVX) are more defensive but have still moved meaningfully. Investors should consider trimming these, though less so than high-beta independent E&Ps. The integrated majors offer dividend support on the downside, but the margin of safety has narrowed.

What to Hold More Confidently

Of course, not all energy equity segments carry the same risk profile. Some segments are better positioned regardless of how the conflict resolves.

Midstream companies remain well-positioned for long-term holding, given their recent price gains. Pipeline operators and MLPs, including my longtime favorite Enterprise Products Partners (EPD), Energy Transfer (ET), and MPLX (MPLX), have lower direct commodity price sensitivity. Their revenue is primarily fee-based and contract-driven. Midstream has outperformed through the conflict but with less volatility, and its relatively high yield provides a floor. These names form the core of income-oriented energy portfolios because they earn their profits through volume rather than price.

Natural gas-levered equities. I increasingly suspect the LNG angle in the current situation is underappreciated. Qatar’s LNG exports transit the Strait of Hormuz, and disruption to those flows has tightened global LNG markets. North American natural gas producers and LNG exporters operate entirely outside the disruption zone. Cheniere Energy (LNG) is one such example. These companies benefit from the crisis without bearing the risk of its resolution.

Canadian producers are another longstanding favorite of mine, and the structural case for holding them has strengthened beyond the geographic argument I would have made a month ago. Names like Canadian Natural Resources (CNQ), Suncor (SU), and Cenovus (CVE) are geographically insulated from Hormuz risk while benefiting from the combination of sustained higher oil prices and long-lived reserves. The demonstrated vulnerability of Middle Eastern supply infrastructure to military threats permanently increases the strategic value of reserves in politically stable countries with pipeline egress. Canada is the most obvious beneficiary. The market has not fully absorbed this structural shift. Furthermore, pipeline capacity out of Western Canada has improved in recent years and could improve further if political momentum for increased exports builds.

Signals to Trim More or Reverse Course

Historically, it has been prudent to exit energy stocks not when the war ends, but earlier, when the market decides the worst case is off the table. I would watch for these signposts:

Brent sustains below $100 per barrel. If Brent falls below $100 per barrel and fails to reclaim that level within a week, the risk premium is likely to deflate over time. This may be the market’s way of signaling that de-escalation is being priced in. It may be a cue to trim further.

Full Strait reopening or a credible diplomatic framework. Any formal agreement or a credible ceasefire with multinational guarantees would remove the core thesis for elevated prices. In this scenario, I would expect oil to gap down $15 to $20 in a matter of days.

Physical flow normalization. This requires tracking tanker traffic through the Strait. If Western-flagged vessels resume transiting, the supply picture will change materially before official announcements. However, even after a political resolution, the physical normalization of flows will lag by weeks to months. Vessel repositioning, insurance repricing, and cautious operator behavior will create a prolonged tail.

Narrative saturation. Investors should be on guard for moments of maximum complacency. This will be when the consensus shifts to the view that oil will remain far above $100 per barrel indefinitely and that the world has entered a new pricing regime. This will also be when the historical pattern of collapse becomes most likely. It is when the downside risk to E&P stocks is at its highest.

Brent breaks above $130 per barrel and holds. In this scenario, oil prices enter the region of demand curtailment. The market is likely pricing in a full escalation, or Scenario C above. At that point, I would sell my E&P holdings more aggressively, as oil and E&P stock prices will eventually retreat as demand is increasingly curtailed. However, depending on prices at the time, I may add to midstream and LNG names that would benefit from a longer-term dislocation.

Conversely, strategic hoarding is a leading indicator for reversing course, and not trimming. Watch for countries announcing export bans on refined products or accelerated SPR building programs. This behavior, which is already emerging, signals that governments expect a prolonged disruption and are competing for physical barrels. It is bullish for both crude oil and refining margins, and it extends the timeline for any normalization of global balances.

Conclusion

History is clear that war-driven oil rallies are unstable and tend to unwind as uncertainty declines. This episode is different in degree: the disruption is real, the chokepoint is critical, and the system’s capacity to absorb the shock is limited. These factors raise the pricing floor, but they do not eliminate the well-worn historical pattern.

Current prices already reflect a prolonged disruption. The upside from here is incremental, while the downside—though less severe than in past episodes—remains meaningful. That is sufficient to justify reducing exposure at the margin.

I intend to trim high-beta oil exposure by 10% to 15%. I will favor high-quality midstream positions, LNG, and Canadian producers, and I will adjust further as market signals indicate whether the risk premium is beginning to unwind or being reinforced.

Analyst’s Disclosure: Jon Costello has a beneficial long position in the shares of EPD, MPLX, ET, LNG, CVE, SU either through stock ownership, options, or other derivatives.

By: Jon Costello

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

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

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

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

The Supply Deficit Is Larger Than the Headlines Suggest

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

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

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

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

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

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

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

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

The SPR Is a Bandage, Not a Fix

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

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

Crack Spreads Point to Physical Market Tightness

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

Source: RBN Energy, March 26, 2026.

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

Refined Products: The Amplifier

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

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

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

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

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

Timing Works Against a Quick Resolution

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By: Jon Costello

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

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

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

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

The Sulfur Shock Hits Sulfate Producers Hardest

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

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

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

North America’s Demand is Advantaged

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By: Jon Costello

Most commentary on the Iran war has focused on oil. This is understandable due to the oil market’s central role in the global economy and its direct impact on consumers. WTI’s spike from the low-$60s per barrel before the war to $113 shortly after it began, and other events, like the strategic petroleum reserve release, immediately captured public attention.

But an often overlooked trade involves a commodity that gets far less attention: LNG. I’ve followed this market closely as a holder of Cheniere Energy (LNG) since January 25, 2021. Cheniere’s ability to sell cargoes at spot pricing through its marketing of uncontracted production makes it an obvious direct beneficiary of today’s high LNG prices.

Direct LNG plays have been bid up to prices that I believe make them unattractive for long-term holding. But there are secondary plays that benefit from the fact that LNG has no substitutes available at scale, barely any strategic reserves, and no spare global capacity. The most obvious is thermal coal, the only realistic backup fuel for LNG in power generation.

Energy expert Dr. Anas Alhajji recently commented on the bullish prospects for thermal coal, noting its use as a substitute for LNG.

Source: Anas Alhajji, X, March 15, 2026.

The thermal coal market was already tightening before the war. The Iran conflict has accelerated a recovery that was underway. Due to the war’s impact on LNG and the prospect for sustained higher coal prices, thermal coal names are worth considering for investors who expect a prolonged disruption in the Strait of Hormuz and/or continued LNG supply outages.

Impacts on LNG From the War In Iran

The closure of the Strait of Hormuz to commercial shipping in early March shut off roughly 20% of the world’s LNG supply. The world’s largest LNG exporter, Qatar, declared force majeure on its contracts after Iranian drone attacks damaged gas facilities. The attacks also forced QatarEnergy to halt all gas production. A full restart of LNG production will take at least a month, and likely longer.

Whereas oil supply has partial mitigants amid a sustained disruption, such as SPR releases, Saudi and UAE pipeline rerouting, and demand destruction, LNG has none. In fact, U.S. export terminals are already running at or near maximum capacity.

More recent developments further support coal as an LNG substitute. For one, yesterday’s Iranian missile strike on Qatar’s Ras Laffan Industrial City has materially worsened the outlook for LNG supply. QatarEnergy confirmed that the attack damaged two of its 14 LNG trains and a gas-to-liquids facility, taking 17% of Qatar’s LNG export capacity offline for more than three years. The offline capacity represents approximately 12.8 million tons per year. The loss of this capacity would put a severe dent in the looming LNG oversupply that kept me away from other LNG investments. Damage to the Qatar facility is the first sign that the war in Iran has caused more than just a temporary disruption that takes a few weeks to restart. If QatarEnergy’s reports of the damage and repair times are accurate, it represents a structural removal of supply from the global LNG market.

This event has significant implications for thermal coal. Long-lasting damage to Qatar’s LNG supply means that the gas-to-coal substitution trade, which was previously contingent on the duration of the Strait of Hormuz closure, now has a multi-year floor underneath it regardless of whether the Strait reopens. Asian and European utilities that were hedging against a short-term LNG outage may now be forced to secure baseload fuel alternatives for 2027 and beyond, and seaborne thermal coal is the only commodity available at the necessary scale. Newcastle thermal coal prices will likely trade higher after this event.

Coal Substitution

When natural gas becomes unavailable or prohibitively expensive, power generators switch to coal. We saw this in 2022 during the Ukraine crisis, when Russian pipeline gas to Europe was curtailed, and Newcastle thermal coal prices spiked to nearly $400 per ton.

The current disruption is different in several ways. The 2022 ordeal disrupted Russian coal supply, creating a dual shock to both natural gas and coal markets. The war in Iran has not directly disrupted coal supply; it has only removed LNG from the market. This means the coal price increase should be more moderate than in 2022, absent a dramatic escalation. At the moment, Newcastle thermal coal is trading around $132 per ton, up more than 30% year-over-year but far below the 2022 peak.

However, the LNG disruption is arguably more acute. Qatar accounted for approximately 20% of global LNG, and there is zero spare capacity anywhere in the world to replace it. Before the strike on Qatar’s LNG facilities, Morgan Stanley estimated that Japan, South Korea, and Taiwan alone could require an additional 1.5 to 2 million tons of thermal coal imports per month if the Qatari outage persists, an 8% to 10% jump in import demand from those three countries alone. Yesterday’s disruption will further increase their import demand.

Europe is also vulnerable. European gas storage levels started 2026 at just 50 billion cubic meters, or roughly 46% full, versus 63 Bcm in 2025 and 77 Bcm in 2024.

Source: CEEnergy News, March 13, 2026.

European natural gas prices nearly doubled following Qatar’s declaration of force majeure. A UBS report noted that the market has not yet fully priced the gas-to-coal substitution trade into coal equities.

My Top U.S. Thermal Coal Plays

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By: Jon Costello

Please see our previous public write-up on .

Mach Natural Resources LP (MNR) exited 2025 as a fundamentally different company than it was when it entered the year. The company’s growth, its improved prospects amid higher oil prices, and its enhanced exposure to natural gas—all while its units sold at an undeserved discount—led me to buy the units in January of this year at an average cost of $10.83 per unit. I detailed my reasoning here.

Mach’s fourth-quarter results showcase the company’s improving prospects, which support our long-term investment thesis.

Fourth Quarter Results: The First Post-Acquisition Quarter

Mach’s IKAV and Sabinal acquisitions, which closed on September 16, transformed the company from an 84 Mboe/d Anadarko Basin operator into a 154 Mboe/d multi-basin E&P with significant natural gas exposure across the San Juan Basin. The fourth quarter was Mach’s first full quarter of consolidated operations following the September acquisitions.

During the quarter, production averaged approximately 154 Mboe/d, up from roughly 84 Mboe/d in Q2 2025 prior to the deals’ closing. Mach’s product mix shifted meaningfully toward natural gas, which now dominates the production profile, a direct result of the San Juan Basin assets acquired from IKAV.

The pivot toward natural gas was evident in Mach’s quarterly financial performance. Nevertheless, the company still generated 42% of its revenue from crude oil sales.

The fourth-quarter distribution of $0.53 per unit reflects the post-acquisition unit count of 168.2 million and the low average commodity prices prevailing during the fourth quarter.

The company refrained from debt reduction during the fourth quarter but will likely pay down significant debt with the increased cash flow generated at current commodity prices.

Full-Year 2025: Setting the Stage for Distribution Growth

For the full year 2026, Mach produced 21.1 Mboe/d of oil, 369.9 MMcf/d of natural gas, and 20.5 Mboe/d of NGLs at average realized prices of $63.72/bbl, $2.76/Mcf, and $23.00/bbl, respectively. Fourth-quarter production results are in line with management’s full-year 2026 guidance, so they provide a good baseline for estimating future performance.

Revenue hit $1.18 billion with operating cash flow of $507.0 million, capex of $262.2 million, and free cash flow before acquisitions of $244.8 million.

Revenue included $81.3 million in realized derivative gains, attributable to oil prices declining throughout the year against Mach’s hedge book. Operating cash flow reached $507.0 million, while capital expenditures for oil and gas development totaled $262.2 million. Free cash flow before acquisitions came to $244.8 million. In the third quarter, Mach recorded a $90.4 million non-cash ceiling-test impairment, driven by a 12-month trailing price decline following the acquisitions. Net income for the year was $143 million, or $1.09 per diluted unit on a weighted average of 131.5 million units.

Fourth quarter’s $0.53/unit was declared on February 12, 2026, payable against 168.2 million units outstanding, 77% more units than a year earlier. The per-unit figure reflects the impact of Mach’s February 2025 public offering, in which 14.8 million new units were offered at $15.50, and its 49.6 million units issued as consideration for IKAV and Sabinal. Despite the unit issuance, per-unit results remained positive amid volatility in commodity prices throughout the year.

Total cash distributions for 2025 were $244.5 million, nearly equal to free cash flow. The high payout percentage demonstrates management’s consistent execution of Mach’s income-focused model. The variable distribution model works as designed. The amount of cash distributed to unitholders fluctuates in proportion to commodity prices and the company’s capital program.

Acquisition Discipline: Buying When Others Won’t

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