By: Jon Costello

Note to readers: Figures are in U.S. dollars unless otherwise noted.

The oil market has apparently made up its mind. After the late-February strikes on Iran throttled the Strait of Hormuz and left roughly 8 million barrels a day of crude with nowhere to go, Brent spiked about 65%. It has since round-tripped to pre-war levels of about $74 per barrel, its lowest level since the war began on February 28, amid hardening conviction that a U.S.-Iran deal will reopen the waterway any day now. The market is pricing a clean reopening, right on schedule.

I am not convinced. The gap between what the tape assumes and what the Gulf can actually deliver may be an opportunity. A reopening is neither as close nor as clean as the market would have us believe. Tankers have to start entering the Gulf for shut-in wells to be brought back on production. Minesweeping alone takes weeks after any ceasefire, redirected tankers need 30 to 40 days to reposition, and Tehran can keep the mere threat of attack alive to throttle passage at will. If you think flows through the Strait remain constrained and Brent will eventually be bid higher—as we do—then the only real question for investors is how to capture that upside in a durable manner.

That is the case for Parex.

Parex Resources (PXT:CA) produces every one of its barrels in Colombia and ships them out through Caribbean ports into the Atlantic basin, none of which transit the Strait of Hormuz. Yet the company prices off Brent, so a constrained Strait flows straight into its realizations. Investors can therefore obtain full price exposure with zero transit risk. For a crude bull nervous about flows at the chokepoint, that is a rare combination.

What Changed Since I Passed on the Shares at C$21

I avoided Parex in January at C$21.13. At the time, the oil price outlook was bearish. The company’s production had fallen from 54,356 boe/d in 2023 to the mid-40,000s, proved-developed reserve replacement was a dismal 41%, and management had not yet regained credibility after its 2024 Arauca disappointment. A standalone Parex in slow decline did not clear my bar as a long-term investment.

The company is now a different business. In the first half of 2026, Parex agreed to buy Frontera Energy’s (FEC:CA) Colombian assets for roughly $750 million, adding about 37,000 boe/d. The deal closed on June 1. It then struck a partnership with Ecopetrol (EC) on the Casabe and Llanito blocks in the Magdalena Basin. Together, these asset acquisitions raise the company’s production guidance to 82,000 to 91,000 boe/d in the second half, nearly double its former base. The production-decline problem I discussed before the deals has become a scale-and-deleveraging problem. The question of management’s credibility has not vanished, but the business beneath is fundamentally different.

Adding to Parex’s allure is the decisive change in the political backdrop that occurred last weekend. President Petro’s freeze on new exploration licensing held back the entire Colombian sector for years, but his movement has lost power. On June 21, the pro-hydrocarbon candidate, Abelardo de la Espriella, narrowly defeated the Petro-aligned Iván Cepeda. His administration is expected to restore exploration contracting, ease the regulatory posture toward operators, and rebuild Ecopetrol, Parex’s partner on the Magdalena blocks and across the Llanos. The result points to a materially less restrictive operating environment for every E&P in the country, and a Colombian producer is the most direct beneficiary of that shift.

We believe that energy investors who had written off Colombia should look again, and Parex, as the largest independent oil producer in the country, is the natural place to start. Much of this is not yet in the share price.

A High-Torque Call on Oil Prices

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Abelardo de la Espriella just won the Colombian presidential election. This is a major victory for oil producers in the country because Petro (the current president) has been very anti-oil. Jon Costello, our head of research, has documented in his Ecopetrol write-up, which I will share below.

Right off the top of my head, I would expect Colombian oil producers to benefit.

These names include: Parex Resources, Geopark, Fronterra, Gran Tierra, Ecopetrol, and New Stratus Energy.

In this report, you will see our individual write-ups on Parex, Geopark, and Ecopetrol.

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By: Jon Costello

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

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

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

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

Mach Captures the Oil Upside While Maintaining Downside Protection

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

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

The Hedges That Capped the Upside Are Rolling Off

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

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

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

Management Is Already Drilling for $95 per Barrel Oil

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

Second-Half Cash Flow Rises Even Against the Hedge Cap

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

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

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

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

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

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

Leverage Falls Without Touching the Distribution

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

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

What Would Break the Thesis

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

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

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

Conclusion

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

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

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

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

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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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 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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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 MNR 1.10%↑.

(Public) Mach Natural Resources Enters The Buy Zone

HFI Research

·

November 12, 2025

Please read our previous article on MNR for context.

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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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Latin America hasn’t been near and dear to the hearts of most energy investors in recent years. The region’s volatile political backdrop has heightened the risk of permanent loss for investors while introducing significant volatility into its E&P stocks.

In Argentina, years of capital controls, currency instability, and interventionist economic policy kept foreign investment out of the Vaca Muerta shale play despite its world-class resource potential.

In Colombia, President Gustavo Petro’s administration actively discouraged hydrocarbon development, banning fracking and suspending new exploration rounds.

And in Venezuela, two decades of mismanagement under Hugo Chavez and Nicolas Maduro collapsed what was once the largest oil producer in the hemisphere.

What makes the current moment interesting is that all three countries are moving in a more constructive direction simultaneously. A combination of favorable political shifts, world-class geology, and compelling valuations makes this corner of the energy market worth a closer look.

Production Regions and Their Prospects

The headline Latin American oil production growth story is Argentina’s Vaca Muerta shale formation. In late 2025, Argentina hit record crude oil production of over 860,000 bbl/d, driven primarily by the Vaca Muerta, where output surged roughly 26% year-over-year. Argentina exported an average of 180,000 barrels per day in the first half of the year and posted its largest energy trade surplus in over three decades. The Vaca Muerta Oil Sur pipeline, led by YPF, is expected to begin operations in 2026 and reach full capacity of 380,000 barrels per day by mid-2027. Argentina’s Chamber of Hydrocarbons Exploration and Production expects the country’s total output to approach 1.5 million barrels per day by 2030.

Colombia remains the other major basin for independent E&P operators. The Llanos and Putumayo basins host the majority of non-state production, though the regulatory environment has been challenging under President Petro’s administration. Production from independents has been steady but stagnant, and the near-term outlook hinges on the May 2026 election.

Colombia’s upstream potential extends beyond what current production levels and trends suggest. The country’s proven reserves stand at 2 billion barrels. They have been declining largely because the Petro administration froze new exploration licensing, shutting down the pipeline of future discoveries. However, the geology is not the problem. The Llanos basin remains underexplored in its deeper formations, while the Middle Magdalena Valley holds meaningful shale potential that has been locked up by the fracking ban. Furthermore, Colombia’s offshore Caribbean blocks have attracted early-stage interest from majors but have never been properly developed. A post-Petro administration that reopens exploration rounds and lifts the fracking moratorium would not just stabilize production, it would reopen a country that was, until recently, one of the most attractive independent E&P markets in the hemisphere.

An Opening in Venezuela

Venezuela is the wild card. Following Nicolas Maduro’s removal in January 2026, the country’s oil sector is in the earliest stages of what could be a multi-decade recovery. Production currently sits around 900,000 to one million barrels per day, a fraction of the 3.5 million barrels per day Venezuela produced in the late 1990s. The Trump administration has begun to selectively roll back sanctions to enable oilfield equipment imports and authorized commodity traders to resume Venezuelan crude exports. Analysts estimate production could reach 1.2 million barrels per day by the end of 2026 if the sanctions rollback continues, but restoring output beyond that level would require sustained investment of approximately $8.5 billion per year over the next decade. The opportunity is enormous, but so is the execution risk. That said, the direction of travel is clear: for the first time since the early 2000s, Venezuela is moving toward a framework that could accommodate meaningful foreign participation in its upstream sector.

The bull case for Venezuela centers on acting President Delcy Rodriguez. Rodriguez served as Maduro’s executive vice president and was one of the most powerful loyalists in his inner circle. This makes her pivot toward market-friendly oil reform all the more striking, because it signals a pragmatism on the part of the regime’s establishment that was absent under Maduro.

For weeks after Maduro’s removal, Rodrigues pushed back on Washington’s demands. More recently, however, she has moved to align with the Trump administration on Venezuela’s energy policy. In late January 2026, Rodriguez signed into law a sweeping oil industry overhaul that ends PDVSA’s monopoly over production and sales. The law also allows private companies to assume full operational control of projects, caps royalties at 30%, and provides the executive with flexibility to adjust rates based on capital needs. It also permits independent international arbitration of disputes, thereby removing the previous requirement that all disagreements be settled in Venezuelan courts.

U.S. Energy Secretary Chris Wright toured Chevron-PDVSA joint venture facilities in the Orinoco Belt in February, and Interior Secretary Doug Burgum visited Caracas in early March to discuss expanding oil and mineral production. Trump has publicly called the relationship “extraordinary.” If Rodriguez continues on this trajectory, Venezuela could become the most significant new upstream opportunity in the Western Hemisphere, a country that claims 300 billion barrels of proven reserves and produces under a million barrels per day, with a legal framework now designed to attract the foreign capital and expertise it needs to resuscitate production growth. For LatAm-focused E&Ps with operational expertise in heavy oil and complex political environments, the window is opening.

The bear case for Venezuela is that Rodriguez remains deeply unpopular among the Venezuelan public. Polling from January 2026 shows Rodriguez with a favorable image of only about 13%, and 94% of Venezuelans say they don’t believe anyone from the Maduro regime should lead the post-Maduro transition. The opposition leader, María Corina Machado, polls at roughly 50% vote intention in a hypothetical election and dominates the field.

This is the hazard that confronts investors who enter Venezuela. Rodriguez is doing what foreign investors want—signing oil reform laws, welcoming U.S. officials, opening PDVSA to private operators—but she has little domestic legitimacy. Ultimately, she’s an insider from the Chavez era governing without a popular mandate, and Washington has shown no urgency to push for elections. The Venezuelan opposition has called for a democratic transition and elections as a precondition for long-term investment stability. Perhaps Rodriguez can win public support by reviving the domestic economy and introducing reforms that weaken the corrupt Chavez-Maduro regime’s grip over the society and its institutions. If so, she stands a chance at the polls come election time. If not, she can refuse to step down or yield to a more popular candidate, which at the moment would be Machado. I don’t have any insight into which way it will go. I mention it because any investor pursuing ownership stakes in Venezuelan assets should proceed with a clear-eyed view of political risk, which will remain heightened until a stable and functioning democracy is established.

Political Tailwinds

Despite the regional risks, the political backdrop across Latin America has turned more constructive than it has been in years.

In Argentina, President Milei’s pro-market reforms have been transformative for the energy sector. Deregulation, macroeconomic stabilization, and the active courtship of foreign capital have directly translated into rising production and surging exports.

In Colombia, President Petro, who banned fracking, halted new exploration rounds, and openly discouraged hydrocarbon investment, is constitutionally barred from re-election. The presidential election is scheduled for May 31, 2026, and the leading candidates from the center and right have signaled a return to more conventional energy policies. A new administration that resumes exploration licensing would be a meaningful catalyst for Colombian-focused E&Ps.

In Venezuela, the post-Maduro transition has opened a window that had been closed for years. The U.S. has signaled its intent to rebuild Venezuela’s oil infrastructure and has authorized the import of oilfield equipment and services. Chevron has maintained operations throughout the sanctions era and is positioned to expand. For smaller operators with Latin American expertise, the question is not whether Venezuela represents an opportunity — it clearly does — but when the regulatory and contractual framework will be stable enough to commit capital. That process is underway but far from complete. JPMorgan estimates Venezuelan production could reach 1.4 million barrels per day within two years and potentially 2.5 million barrels per day over the next decade, but that assumes sustained capital commitment and political stability that cannot yet be taken for granted. The companies best positioned to participate are those already operating in the region with established relationships, local expertise, and the operational flexibility to move quickly when the framework solidifies.

Latin American E&Ps

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By: Jon Costello

In November, I wrote that a recovery in the titanium dioxide market appeared imminent. With fourth-quarter results now in for Tronox , Chemours , and Kronos Worldwide , it is clear that the fourth quarter was the most painful of the current downcycle, which has dragged on for more than four years.

Results were ugly all around. Kronos’ EBITDA collapsed 94% year over year. Tronox posted negative free cash flow of $281 million, and Chemours’ titanium dioxide segment saw its weakest results since becoming a public company.

As bad as the results were, the investment case for these companies is stronger today than it was just four months ago. More than 1.1 million tons of capacity—approximately 11% of the global market—has been removed through plant idling, shutdowns, and business liquidations. The large-scale inventory liquidation that persisted throughout much of 2025 has run its course.

The Supply Side Will Drive the Recovery

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By: Jon Costello

The HFIR Coverage Universe spreadsheet has been revised and updated. The spreadsheet ranks 46 E&Ps covered in our articles over the past few years and can be found at the bottom of this article.

Each E&P has data as of Q4 2025 or full-year 2025. Full-year 2026 guidance has been incorporated when available. Nine names have yet to report fourth-quarter results. Results from these companies are as of September 30, 2025.

The spreadsheet data provides important information on investment opportunities among the stocks in our E&P coverage universe, including their potential upside and downside from current prices.

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Previous write-ups on :

Special Situation: Calumet

(Idea) Calumet - The Next Special Situation Idea

(Idea) An Important Update On Calumet

By: Jon Costello

The market reacted negatively to Calumet’s (CLMT) fourth-quarter earnings. The magnitude of the selloff is puzzling given the company’s increasingly bullish near-term outlook. Still, longtime holders of the shares are no strangers to these head-scratching selloffs that have occurred consistently for many years.

The initial sell-off was likely a reaction to the company’s poor results, brought about by the worst operating environment for biofuel in the industry’s history. Fortunately, those results are now squarely in the rearview mirror, and the company’s future looks considerably brighter.

The fact is that biofuel economics have improved in recent months and are expected to continue to improve after the EPA announces the renewable volume obligation (RVO) for buyers of Calumet’s biomass-based diesel. The RVO is the government-mandated volume of biomass-based diesel that refiners are required to blend into the petroleum supply. The EPA’s announcement is expected to arrive in mid-to-late March. A bullish RVO in the mid-five-billion-gallon range is likely to cause a scramble for renewable diesel among refineries that will push biomass-based diesel prices higher. Of course, higher prices will significantly boost Calumet’s margins, EBITDA, and free cash flow.

The stock’s recent run-up reflects investor expectations that the looming RVO will drive a bullish inflection in Calumet’s end markets over the next few months.

As detailed in articles published last year, I expect the announcement to be bullish due to its political ramifications for President Trump’s voter base. A bullish RVO can drive Calumet shares toward $40 over the latter half of the year. Risk-seeking long-term accounts should hold onto their shares in anticipation of this event. However, risk-averse accounts should consider lightening up, as a light RVO could spark a selloff.

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On Jan 3rd, the US successfully captured Venezuelan President Nicolás Maduro and took him into custody. At the time, we gave our general thoughts about the regime change and its impact on the oil market. But a lot has changed since then. Our initial belief that the procedural changes would take time has been proven inaccurate. Instead, what we are seeing is a rapid change from both the US and the Venezuelan side to expedite investment and the restart of the oil industry.

In this article, I will give you a breakdown of the following:

• All the changes that have taken place.

• The impact on the global oil market.

• Potential investment opportunities.

What Changed?

The Trump administration has moved aggressively to reopen the Venezuelan petroleum sector to the US and allied commercial interests. Between the end of January to mid-February, the US Department of the Treasury’s Office of Foreign Assets Control (OFAC) issued a series of General Licenses that systematically unraveled the sectoral embargoes imposed under Executive Orders 13850 and 13884.

• General License 46A: Authorizes established U.S. entities to engage in the lifting, exportation, sale, and transportation of Venezuelan-origin oil. Contracts must be governed by U.S. law. Reporting to the State Department is required every 90 days.

• General License 47: Permits the export, supply, and delivery of U.S.-origin diluents to Venezuela, critical for blending extra-heavy crude. Prohibits transactions with persons in Russia, Iran, North Korea, Cuba, or the PRC.

• General License 48: Authorizes the provision of goods, technology, and software for the exploration and production of oil and gas. Expressly prohibits the immediate formation of new joint ventures without separate licensing.

• General License 49: Allows for the negotiation and entry into “contingent contracts” for new capital investments in the energy sector. Actual execution and performance of these contracts remain contingent upon future specific OFAC authorization.

• General License 50A: Provides targeted authorizations for specific major U.S. and European energy companies to resume designated operations. Excludes the use of debt-for-oil swaps, gold payments, or Venezuelan digital currencies like the petro.

With these general licenses in place, US and foreign oil companies can now invest in Venezuela.

The other big change was to the payment mechanism. One of the main concerns for capital flows to Venezuela was the billions in international arbitration awards held by multinational companies. To prevent legacy creditors from immediately seizing new oil revenues through international courts, President Trump promulgated Executive Order 14373 on January 9.

Here’s how the new payment structure works:

• Under the new General Licenses (GL 46A and GL 48) issued by OFAC, foreign oil companies are prohibited from paying the Venezuelan government or PDVSA, the state-owned oil company, directly.

• Any royalties, federal taxes, or production levies owed to Venezuela must be deposited into US-controlled accounts known as “Foreign Government Deposit Funds.” This was established under Executive Order 14373.

• Companies are only allowed to make direct payments to Venezuelan authorities for routine local taxes, permits, and fees. This avoids any potential mishandling of funds from the oil revenue.

• To access the oil revenues held in the US accounts, the Venezuelan acting government must submit a “budget request” to Washington DC, which authorizes the release of funds for approved purposes, such as importing medicines and medical equipment. This mechanism effectively chokes off any potential disruptions to the oil industry and gives the US effective control of all of Venezuela’s finances.

Note: It is incredible to think just how powerful the US is when you read the specific mechanisms.

The payment arrangement also explicitly prohibits the following (General License 50A):

• Debt-for-oil swaps, this effectively nullify all of the Chinese deals made in the past.

• Payments using gold.

• Venezuelan state-issued digital currencies.

Not only are drastic changes happening on the US side, but there were profound changes made on the Venezuelan side.

On January 29, the Venezuelan National Assembly enacted sweeping amendments to the Organic Hydrocarbons Law. Without these changes, the US General Licenses would not have been enough, and here’s why:

• Direct Private Participation and Contractual Freedom: The reform explicitly repeals the 2006 law that reserved upstream activities to the state. It also repeals the 2009 law reserving hydrocarbon-related assets and services to the state. Private companies in Venezuela can now hold direct upstream contracts for exploration, extraction, collection, transportation, and storage without the historically mandatory requirement of majority state ownership (this is a big deal, more on this later). In addition, these upstream contracts are exempt from traditional Venezuela public procurement laws, which dramatically streamlines their negotiation and execution.

• Minority Shareholder Empowerment: In existing “Mixed Companies” (join ventures with PDVSA), minority foreign partners are now legally permitted to exercise direct technical and operational management (another big deal, more on this later). This bypasses PDVSA’s notorious bureaucratic inefficiencies and technical deficiencies. Furthermore, minority partners can now directly market their share of the production and independently open and manage bank accounts in any currency and jurisdiction offshore, thus drastically mitigating local currency devaluation risks and capital repatriation risks.

• Arbitration and Dispute Resolution (arguably, the most important change implemented by Venezuela): A major impediment in the past on energy investment has been Venezuela’s insistence on local judicial jurisdiction. The new reform permits the state to relinquish its absolute sovereign immunity in contract disputes allowing for international arbitration clauses. This was a major mandatory prerequisite for oil majors to even contemplate the first step.

• Fiscal Flexibility and Taxation: The reform caps baseline royalties at a competitive 30% and introduced a streamlined 15% Integrated Hydrocarbons Tax. In addition, it actively exempts operators from a raft of punitive legacy taxes and completely repeals the 2013 windfall tax law. The changes also exempt entities from large wealth tax, localized social contributions for science, technology, sports, and pensions (crazy, I know).

The changes on the Venezuelan side were what came as a surprise to me. When we wrote up our piece on Jan 3, we thought a regime change was required to enact a lot of the changes here, but it appears Delcy Rodríguez, the current sitting Venezuelan President, got the message quickly. With these changes in place, energy companies have lined up to review the potential investment opportunities in Venezuela.

Oil Market Implication

Venezuela is currently exporting ~1 million b/d of crude. With the General Licenses issued, Venezuela will no longer need to secretly import Iranian condensate and wait for the tankers to return from China. The US will be able to provide the critical diluent Venezuela needs to mix with the heavy sour crude it produces.

Reduced shipping time, coupled with less friction on oil transactions, should see Venezuela’s crude export average ~1.1 to ~1.2 million b/d for 2026. From a production standpoint, we won’t see any meaningful uptick this year as oil companies are still evaluating investment opportunities. But given the expedited timeline of the legal framework, we see Venezuelan crude oil production inching to ~1.4 to ~1.6 million b/d by the end of 2027 to early 2028. This represents an increase of ~400k to 600k b/d from the current production level.

By our estimate, global oil supply & demand will need the extra Venezuelan crude. Q4 2027 oil market deficit is estimated at -0.7 million b/d and non-OPEC supply growth will have all but disappeared by then.

After 2028, we see Venezuela gradually increasing to ~2 million b/d by early 2030s. This level of production will require 1) a stable political landscape and 2) a supportive government like the one we’ve seen thus far.

Given that the US controls the finances, I believe that the foundation for stability in energy investment is sound. Oil majors, however, will remain reluctant to dive headfirst into the Venezuelan oil sector.

Rystad estimates that it would take $183 billion in capex just to push Venezuela’s oil production higher. This is achievable if you look out to 2040, but that’s a long road from today.

Investment Opportunities

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Editor’s Note: Please also read the original Chemours write-up.

Ideas from HFI Research

(Public) Chemours - Jon's Favorite Capital Cycle Investment Idea

Editor’s Note: This article was first published to paid subscribers on Nov 15. The thesis for remains intact…

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5 months ago · 5 likes · HFI Research

By: Jon Costello

Chemours reported fourth-quarter 2025 results last Thursday, February 19. The results fell short of consensus expectations and caused the shares to decline by 25% from peak to trough over two days. After bottoming at $16.15, the shares have since recovered to $18.41, still shy of their recent high before earnings of $21.85.

While the fourth-quarter results were weak, management’s forward-looking expectations were considerably more optimistic. Overall, I expect results to improve over the course of 2026. A sustained recovery in the titanium dioxide market should support further gains in 2027. My Chemours investment thesis remains intact, and the shares remain attractive at their current price for a three-year or longer holding period.

The Cause of the Selloff

Without a doubt, the fourth quarter results were ugly on a GAAP basis, as the ongoing downturn in its Advanced Performance Materials (APM) and Titanium Technologies (TT) operating segments weighed on corporate profitability.

The consolidated quarterly results comparison is shown below.

Source: Chemours Q4 2025 Earnings Conference Call Presentation, Feb. 20, 2026.

As the table shows, cash flow results during the quarter were better. Operating cash flow was flat year over year, and capex was down significantly.

Management cited the impact of adverse “cost absorption,” or negative operating leverage, which occurs when sales volumes fall faster than unit costs and lower Adjusted EBITDA. Management also attributed the poor results to an unfavorable sales mix in the APM segment and higher taxes.

The reason why the shares sold off so sharply after earnings was that they ran so hard into earnings.

When the optimistic sentiment was met with a “meh” earnings report and near-term outlook, it’s no wonder that some investors decided to take profits rather than wait for clear signs of a more robust and sustainable recovery. If fundamentals continue to improve over the coming quarters—driving Adjusted EBITDA higher—I expect the shares to perform well from the current price.

Why the Selloff was Overdone

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Please be sure to read our primer on the chemical sector and the titanium dioxide market.

Ideas from HFI Research

(Public) Primer On Investing In The Cyclical Chemical Sector

Editor’s Note: The piece below is a compilation of all of the chemical sector write-ups we published since October 2025. We hope readers will find this helpful in navigating what we think is the trough in the special chemical space…

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4 months ago · 11 likes · HFI Research

By: Jon Costello

Tronox Holdings’ (TROX) fourth-quarter 2025 results point to a recovery in its earliest stages, with volumes clearly inflecting higher and prices lagging.

The company’s fourth-quarter revenue came in at $730 million, up 8% year over year and 4% from the previous quarter. The performance was driven almost entirely by higher sales volumes, which increased by 13% from the previous quarter. The result was ahead of management’s expectation of a 3% to 5% improvement. Meanwhile, Zircon volumes were up 27% year-over-year and 95 from the previous quarter.

The volume outperformance was driven by activity in India, Latin America, and the Middle East, where antidumping duties against Chinese imports have created opportunities for non-Chinese producers to gain lasting market share.

While the fourth-quarter volume recovery was real, it was met with continued pricing deterioration. Titanium dioxide prices declined roughly 8% from the fourth quarter of 2024, while Zircon prices declined by 23% over the same period.

The result of the higher volumes and lower price was Adjusted EBITDA of $57 million on a 7.8% margin, down 56% from $129 million in the year-ago quarter. Full year 2025 EBITDA was $336 million, down 40% from $564 million in 2024, on revenue that declined by only 6%. Quarterly results are shown in the table below.

The table shows that Adjusted EBITDA margins deteriorated in each quarter of 2025, even as volumes recovered in the second half of the year. Pricing was the culprit, compounded by cost headwinds from lower mining and upgrading rates, resulting in a collapse in fixed-cost absorption. The company also reported $233 million in restructuring charges for the closures of its Botlek facility in the Netherlands and its Fuzhou facility in China, though these were excluded from the adjusted figures.

The 2016-2017 Precedent

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Editor’s Note: We first covered in a write-up back in March 2025. We have made it public to all readers.

Ideas from HFI Research

(Idea) Buy Valaris

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a year ago · 6 likes · HFI Research

By: Jon Costello

Earlier today, Transocean (RIG) announced it will acquire Valaris (VAL) in an all-stock deal valued at approximately $5.8 billion. Under the deal, Valaris shareholders will receive 15.235 Transocean shares for each Valaris share they owned as of February 6, before the announcement. This equals about $82.12 per Valaris share, reflecting a 31.6% premium over Valaris’s $62.41 pre-deal closing price.

Both stocks gained steadily throughout the day. Valaris closed at $83.82, and Transocean closed at $5.71, up 6.1% on the day.

Upon closing, Transocean will have an enterprise value of over $17 billion. Its shareholders will own 53% of the combined company, while Valaris shareholders will own the remaining 47%.

The deal marks a win for investors who purchased Valaris shares in the past eighteen months.

Since Transocean’s offer is for all stock, Valaris shares will swing around with Transocean’s share price until the deal closes. For investors seeking to maintain exposure to a recovering offshore market, it makes sense to hold onto the shares for the long term. I plan to hold all of my Valaris shares and exchange them for Transocean shares, which I expect to hold onto afterward.

The deal is also a win for Transocean shareholders in the near term, primarily because it supports the company’s efforts to delever its balance sheet. The additional operating cash flow from this deal reduces the combined entity’s interest burden relative to the legacy Transocean. Its shareholders will face less financial risk if dayrates were to turn down.

Management expects to realize $200 million in annual cost savings and aims for a leverage ratio of 1.5x Adjusted EBITDA 24 months after closing. The pro forma balance sheet based on the latest financial information shows $5.38 billion in net long-term debt, with $1.37 billion due within one year. Liquidity is strong, with $1.50 billion in pro-forma unrestricted cash and $859 million of pro-forma revolver availability, for total pro-forma of approximately $2.35 billion.

Once the deal closes, I expect management to begin considering reinitiating a dividend and/or share repurchases as the need to reduce debt diminishes.

The main negative for Transocean shareholders is the dilution from this deal. Transocean shareholders will own 51% of the combined entity on a fully diluted basis, resulting in nearly 100% dilution. Still, considering the reasonable price paid for Valaris—assuming the offshore market continues its recovery to new all-time highs—the enhanced earning power, improved market position, and lower risk effectuated by this deal make the dilution worthwhile.

This deal caught me by surprise, as I had agreed with the consensus view among many industry watchers that Valaris would be more likely to combine with Noble Corp. (NE) than with Transocean. Valaris and Noble have more similar fleets, which would yield greater relative competitive improvements and cost savings. However, as a shareholder of both Transocean and Valaris, I like this deal.

Late last year, I soured somewhat on Valaris’ management, particularly its weak capital-allocation performance. Share repurchases were a key part of my Valaris investment thesis, but the company failed to repurchase any shares during the first three quarters of the year, even though it had ample cash that was building over time, a conservative balance sheet, and shares trading at depressed levels. Repurchases made sense and would have been highly accretive. When no repurchases had been made, I was concerned that if management could botch capital allocation, it might botch other important areas of this business, which offers many opportunities for mistakes. I’m pleased that Transocean management will lead the combined entity.

Long-Term Benefits for Transocean

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In the second half of 2025, much of the chemical sector was valued as if it would never recover, with stock prices so low that any sign of a cyclical rebound would trigger a rally. The situation provided investors seeking large long-term returns with an attractive opportunity.

Since we invested in the space in the second half of 2025, chemical stocks have started to recover.

Further gains are likely if the recovery continues. What were potential three- or four-baggers a few months ago can still double or more from their current prices.

For investors seeking to understand the cyclical chemical sector, this article reviews several of my macroeconomic and company-specific investment theses.

A cyclical recovery is likely in the chemicals sector, as each subsector undergoes its own adjustments between supply, demand, and prices. Although the timing of a recovery is uncertain, chemical stock prices had declined to levels that made prospects for doubling in the next two or three years promising.

I published four articles on the chemical sector and why I believe it is undervalued in these three articles:

A Titanium Dioxide Market Recovery Appears Imminent

The Chemical Sector Overview: Olefins And The Rest

Chemical Sector Macro 2: The Current Downturn And Prospects For A Recovery

Chemical Sector Macro 3: Lessons From Past Cycles Applied To Today’s Stocks

Characteristics of the Current Downturn

For much of the chemical industry, the downturn started in 2021. Many companies saw utilization drop below 80%, and margins hover around cash costs. Within the industry, it felt like a recession, even though overall GDP kept growing. Meanwhile, investors who had faced years of losses abandoned the sector and sold their stakes.

This unique circumstance—where the overall economy grew but chemical subsectors were stuck in a cyclical downturn—created an opportunity. Many investors and sell-side analysts were waiting for a recession to hit before purchasing the more cyclical chemical stocks. A recession would lower prices, but it would also speed up the sector’s recovery by forcing a supply adjustment. If, on the other hand, a recession failed to materialize, a strong rally could be in the cards.

The chemical sector’s downturn had three overlapping drivers:

1. A global capacity buildout. This was most pronounced in olefins.

2. Weak industrial end markets in key regions. Europe’s high energy costs, restrictive regulations, and shrinking manufacturing base have hurt global chemical demand. Weakness in China’s property and heavy industry. A downturn in North America’s housing and construction markets. These factors all contribute to weak end-user demand.

3. An abnormally long destocking phase. During the post-Covid supply chain chaos, buyers over-ordered. The resulting inventory excess caused buyers to become more cautious, ordering just enough to manage their bloated inventories. This pattern lasted longer than the typical one or two quarters usually seen in the industry’s inventory cycles. As apparent demand dropped below actual end demand, the weakness in volume and utilization became even more apparent.

These factors led many investors to abandon the entire sector of cyclical chemical stocks. What I believe many overlooked was that, although all stock prices were low, the outlook for individual companies and their stocks was more complex.

For one, downturns and recoveries in the sector occur across distinct value chains, each with its own capital cycle, specific supply-and-demand dynamics, logistical constraints, customer inventory practices, and pricing strategies. As a result, investors who can determine which subsectors or value chains are poised for a recovery can identify high-return candidates.

Next, the sector had to be divided into two groups: value chains that were structurally challenged, and those that were cyclically depressed.

Structurally challenged value chains were parts of the chemical sector where capacity was overbuilt but was politically, strategically, or economically difficult to reverse. The overcapacity keeps prices too low, putting many producers at risk of bankruptcy.

Olefins are the poster child. The subsector saw massive investment from international oil and gas majors in large-scale cracker and polymer units. Overbuilding was most severe in China and North America. Structural overcapacity means that recoveries can be fleeting because new foreign supply keeps arriving once regional prices rise to levels that make imports profitable. Getting a handle on “mid-cycle earnings” for companies stuck in such an environment can be impossible, rendering appraisals of intrinsic value suspect.

I consider companies operating in structurally challenged niches to be uninvestable.

Outside the more structurally challenged subsectors were the areas of potential opportunity. In many cases, the negativity toward structurally challenged sectors led investors to sell across all chemical subsectors, including those that are structurally viable but cyclically depressed.

Cyclically depressed value chains can adjust supply to long-term demand in a way that leads to a sustainable cyclical upturn. These chains experience bankruptcies, production shutdowns, consolidation, and capital starvation, which bring supply into line with reduced demand. The eventual price recovery drives the next upturn.

Given the bargain prices on offer, this subset of chemical names was ripe for long-term investment.

Finding the Best Mispriced Opportunities

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By: Jon Costello

Energy Transfer (ET) units have continued to underperform peers in 2026. Both MPLX (MPLX) and Enterprise Products Partners (EPD) have fared significantly better.

The company’s weak third-quarter results explain the underperformance. ET posted the most disappointing financial results among its peers, with Adjusted EBITDA expected to now fall well short of management’s guidance range.

Despite ET’s recent poor showing, I expect investor concerns about ET relative to its peers will start to diminish over the next few quarters as its growth spending spree ramps down and new projects add to EBITDA. ET’s weak results, current out-of-favor status, and better-than-appreciated prospects bode well for its shares over a three-to-five-year timeframe. Its 8.1% distribution yield makes the units particularly appealing to investors seeking income.

Weaker than Expected Third-Quarter Results

During the third quarter, ET posted strong operating performance and weak financial results. The financial performance was weak relative to ET’s recent history, though less so than those of its large-cap midstream peers.

The trend underlying ET’s operating results remains intact. Volumes continue to increase across the board, with the exception of the intrastate natural gas transportation segment, as shown in the following table.

ET didn’t elaborate much on the cause of weakness in its intrastate gas volumes during the quarter, but I suspect it is tied to the company’s decision to transition customers away from optimization and toward third-party contracts. This means that they’re shifting from essentially an arbitrage business to stable transportation to a fixed fee. Volumes may be declining temporarily during the transition. In any event, I view the quarter’s results in this segment as a one-off and not a cause for concern in the long term.

Financial results for the third quarter were disappointing, falling short of analyst and my own expectations. ET reported Adjusted EBITDA of $3.8.3 billion, missing analyst expectations of $3.97 billion by 3.5%. Results were weaker than both the previous year’s and the previous quarter’s results, as shown below.

This is clearly disappointing. I suspect the severe intrastate natural gas result was attributable to the switchover to third-party contracts.

While the weak showing doesn’t exonerate ET’s management, it’s worth noting that the company’s weak financial performance wasn’t exceptional in the midstream sector. It joined Enterprise Products Partners, Plains All American (PAA), Kinder Morgan (KMI), and Enbridge (ENB) among major midstream operators who missed analysts’ third-quarter earnings expectations. It was actually a lousy quarter for the group. Only Western Midstream Partners (WES) and South Bow (SOBO) surprised meaningfully to the upside.

On a consolidated basis, ET outspent its free cash flow by $415 million during the quarter. The culprit was higher costs, both operating expenses and capex. Growth capex is particularly heavy this year, and is set to remain so over the coming quarters.

ET is currently tracking at full-year Adjusted EBITDA of $15.74 billion, approximately 4% below the lower end of management’s initial full-year guidance range of $16.1 to $16.4 billion. The table below shows how full-year 2025 performance is tracking. Growth capex is adjusted higher, to $4.6 billion, consistent with management’s guidance. ET will have to fund its $1 billion cash flow shortfall with additional long-term debt.

Operating Costs a Cause for Concern

The biggest concern with ET’s third-quarter results was a significant year-over-year increase in operating costs. The higher costs go a long way toward explaining why a strong operating performance can be matched with a weak financial performance.

Much of the cost was attributable to higher ad valorem taxes, but these aren’t necessarily one-time expenses. Ad valorem taxes are property taxes assessed on a company’s assets. When a midstream company places new assets into service, its ad valorem tax obligation increases. Typically, the increase translates into higher operating expenses, though they should be offset by the margin generated by the asset.

ET did have some one-time items that reduced third-quarter Adjusted EBITDA. The NGLs segment had one-time investigation and remediation costs of $17 million, and the Interstate natural gas segment had a one-time ad valorem tax of $43 million related to its Rover pipeline. The latter probably relates to a tax dispute over prior-period taxes that ET must have lost.

The company’s disclosures on its higher operating expenses provided little insight. And not surprisingly, there were no questions from analysts about the operating cost increase on the third-quarter earnings conference call.

At this point, we have to rely on management to be aware of the issue and take action to reduce costs. There is always a risk that costs will get out of hand in capital-intensive, expansionary companies like ET, which are constantly building new projects and acquiring new assets. Fortunately for ET’s equity owners, there is good reason to believe that management has become more disciplined and can address the cost issue.

The Good News

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Editor’s Note: Rich Kruger and his team continue to deliver outstanding operational results for shareholders. This is our favorite integrated oil major name.

By: Jon Costello

Note: This article cites Canadian dollars unless otherwise specified.

Suncor Energy (SU) (SU:CA) reported yet another outstanding, record-breaking quarter. Year-to-date, it has shattered its initial 2025 guidance. In the process, it has significantly exceeded even my own elevated expectations.

Another Blowout Quarter

During the third quarter, Suncor reported adjusted funds from operations (AFFO) of $3.83 billion, up from $3.79 billion in the previous year despite 13.6% lower quarterly average WTI prices. The result was the company’s second-highest quarterly AFFO ever, and its highest since the third quarter of 2022, when WTI traded around US$90 per barrel.

Free cash flow came in at $2.39 billion, with WTI averaging US$64.95 per barrel. Annualizing the free cash flow, Suncor’s shares trade at a 13% free cash flow yield during a period of depressed oil prices. Of course, free cash flow will surge significantly higher as oil prices increase. The share price will likely follow.

During the quarter, the company returned $1.44 billion of free cash flow to shareholders. It also increased its quarterly dividend by 5%, to $2.40 on an annualized basis, for a safe and attractive 4.0% yield on its current $60 stock price. The company was also active in repurchasing shares, repurchasing $250 million every month so far this year. Year-to-date, it has repurchased 3.4% of its common shares outstanding, $340 million more in repurchases than in 2024, even though oil prices averaged $9 per barrel lower this year.

Suncor’s impressive financial achievements were facilitated by its unique integrated business model, which allows it to capture margins throughout the oil and refined product value chains.

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