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.

Read more

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

Read more

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

Read more

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.

Read full story

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

Read more

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

Read more

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

Read more

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.

Read more

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.

Read more

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

Read more

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…

Read more

3 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

Read more

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…

Read more

3 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

Read more

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

Read more

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

Read more

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

Read more

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

Read more

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.

Read more

By: Jon Costello

Greenfire Resources (GFR) (GFR:CA) is in the bull’s eye of what today’s market dislikes. It’s a microcap Canadian oil-sands producer that has been beset by management upheaval and operational mishaps since it came public in September 2023. The most recent headwind for GFR shares was the company’s dilutive rights offering, which increased the share count by 78% overnight on December 16.

Despite all the negatives, GFR’s prospects over the next few years are bright if oil prices increase as we expect. The fact is that energy investors today confront the difficult reality that E&P stocks are priced to reflect WTI in the low-US$70s per barrel, while the benchmark trades below US$60. Given the mispricing of so many of these stocks, investors who believe higher prices are imminent and that WTI will average more than US$70 per barrel over the long term may find GFR to be an attractive E&P alternative.

Background

GFR came public through a SPAC merger on September 21, 2023. The company was run by a team that appeared competent on paper but proved unable to meet its production objectives.

In September 2024, the Waterous Energy Fund (WEF) acquired a 43% stake in GFR’s common stock, primarily by acquiring blocks of shares from large shareholders. Waterous and the affiliates of the SPAC sponsor waged a proxy battle that ultimately ceded control to WEF, which emerged with a controlling 56.5% ownership interest in GFR’s common shares in late 2024.

WEF replaced GFR’s management team over the subsequent months, installing its own candidates, including Colin Germaniuk as President. Germaniuk is an engineer by training who possesses extensive experience in managing SAGD assets. His qualifications include being one of the earliest employees at Serafina Energy. Serafina owned and operated SAGD assets in Saskatchewan, growing production from zero to 40,000 boe/d over eight years. It was subsequently acquired by the WEF-controlled Strathcona Resources (SCR:CA) in August 2022 for $2.3 billion.

GFR currently trades at a market cap of $798 million based on its 125.4 million shares outstanding. In recent weeks, it completed a $300 million rights offering and redeemed its $237.5 million in 12% Senior Secured Notes due 2028. I assume it also used the offering to pay off the $50 million balance on GFR’s revolving credit facility. Combined with the $114.7 million in cash on the balance sheet at the end of the third quarter, the transactions have left the company with a large net cash balance and an enterprise value well below its market cap. The rights offering has de-risked the balance sheet, improved the company’s cash flow profile, and enhanced its operational flexibility.

After the rights issue, WEF owned 71.1% of GFR equity. Since WEF gained control of GFR, a major unresolved issue for GFR shareholders was what it planned to do with the company after having taken control. Was it going to fold GFR into Strathcona, or operate it as a standalone company and as a separate investment in one of its private equity funds?

Management’s comments suggest it plans to operate the business as a standalone entity and keep its public stock listing. I suspect it is doing so because GFR’s assets are not necessarily a proper fit within the larger Strathcona entity. Also, GFR presents relatively more upside given its smaller size, more focused operations, and greater torque to oil prices than Strathcona. The WEF also benefits from GFR’s public listing by providing a means to incentivize management and offering liquidity to the limited partners in its Waterous Energy Fund III fund, which holds GFR shares.

My previous GFR articles discuss GFR’s Expansion and Demo assets in the Hangingstone area of the Athabasca region in Alberta. The assets are located in the heart of oil sands country:

Source: Greenfire Resources Aug. 2024 Corporate Presentation.

While GFR’s Hangingstone assets aren’t of the highest quality among Canadian SAGD assets, they are among the highest quality of the SAGD assets not already owned by a larger operator.

Asset Value Exceeds Enterprise Value

Read more

By: Jon Costello

This morning, Antero Resources (AR) announced that it would acquire HG Energy, a privately held E&P with operations contiguous to AR’s core in West Virginia. AR is paying $2.8 billion for the assets, while divesting its non-core Ohio Utica assets for $800 million. In a related deal, AR’s midstream operator, Antero Midstream (AM), will simultaneously acquire HG’s midstream system for $1.1 billion and sell its Utica midstream footprint for $400 million.

The deal stands to increase AR’s production from 3.5 Bcfe/d to 4.2 Bcfe/d. The acquired assets are contiguous with legacy AR. After the Utica divestiture, the company will emerge with the entirety of its production located in the core of the Marcellus in West Virginia.

Source: Antero Resources, Strategic Transaction Slide Presentation, December 2025.

This deal essentially represents Antero selling a smaller, higher-multiple, non-core asset and reinvesting the capital into a larger, lower-multiple, core asset. In the process, it will keep its investment-grade balance sheet intact by financing the deal with a three-year term loan, free cash flow, and proceeds from the sale of the Utica asset.

AR will emerge from the deal with a materially greater liquids weighting. The acquired assets produce 75% liquids, so AR’s liquids weighting will increase from 38% before the deal to 46% after the deal. We’re bullish liquids over the long term, so we view this as a net positive, as it reduces risk to shareholders if the natural gas bull market underwhelms relative to today’s rosy expectations.

While leverage will tick higher, the deal is likely to be accretive on an NAV and operating cash flow basis at natural gas prices above $3.00. We remain constructive on natural gas prices over the coming years, so we like this deal. AR will emerge with lower cash costs and operations concentrated in the core of the Marcellus, one of the world’s lowest-cost natural gas basins.

Read more

By: Jon Costello

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

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

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

ASIX Overview

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

Nylon 6 & Caprolactam

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

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

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

Source: AdvanSix 2024 10-K.

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

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

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

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

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

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

Ammonium Sulfate

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

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

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

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

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

Chemical Intermediates

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

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

Undergoing a Cyclical Downturn

Read more

By: Jon Costello

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

Chemours Overview

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

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

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

When combined, Chemours’ cyclicality is evident.

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

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

Thermal & Specialized Solutions (TSS)

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

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

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

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

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

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

Titanium Technologies (TT)

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

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

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

Advanced Performance Materials (APM)

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

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

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

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

Investment Thesis

Read more

By: Jon Costello

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

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

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

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

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

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

Read more