By: Jon Costello

Transocean (RIG) shares have been clobbered over the past few trading sessions, down 25.6% since October 30, versus the XLE’s 12.2% decline over the same period. I believe the selloff is partly due to macro angst toward oil and partly to weak headline third-quarter results, which the company reported on November 2. Overall, I think both are overblown and that the current share price represents a good entry point for investors willing to hold for at least three years.

Macro Oil Weakness

The general macro angst is the easy part to explain. Transocean shares are correlated with oil prices. The company’s large market cap for the energy sector and its relatively high leverage make it a favorite plaything of macro funds looking to short oil through means other than futures. Its short interest is pushing 30%.

The following table shows the tight correlation between Transocean shares and WTI. The relationship is peculiar, as the company’s results and prospects are not tied to spot crude prices. Clearly, they depend far less on spot oil prices than those of many other larger oil companies, such as E&Ps.

As Transocean’s leverage comes down after its Valaris (VAL) acquisition and continued efforts to pay down debt, while its earnings stabilize over the coming quarters, I expect macro funds will grow less fond of using the shares as a shorting instrument. If so, this should temper some of the volatility the shares have exhibited for many years. It might also reduce the tight correlation with oil. Periods of macro oil weakness like this one would be less likely to send the shares reeling.

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For those of you who have followed our investment process closely over the past few years, you will have noticed that we don’t add stock ideas very often to the HFI Portfolio. Most energy names don’t pass the test, and whether it’s valuation or execution issues, we are very picky.

Since the start of the year, we have been very selective. First, I wrote at the start of the year that crude oil would outperform energy stocks, so we took exposure in USO. After the Iran War began, we used several pullback opportunities to add to our long oil ETF exposure.

We remain long the hefty exposure we have in UCO, USO, and BNO. In addition, we remain long a sizable position in BNO call options, which I have detailed in my oil trade game plan articles.

On the stock idea front:

• We bought CNQ in April.

• We bought PXT.TO and GPRK during the July oil selloff. This was part of a broader basket trade in Colombian oil producers.

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By: Jon Costello

Mach Natural Resources’ (MNR) units have been under pressure since early August for two very different reasons. The first was fundamental, with the second quarter coming in weaker than I expected and Mach cut its quarterly distribution to $0.36 from $0.64.

The second was technical. On September 15, Kayne Anderson began marketing 8 million units at a discount to the prior close.

Source: Seeking Alpha, Sept. 15, 2026.

On the first reason for the unit price weakness, second-quarter results do raise legitimate questions about Mach’s reinvestment needs and balance sheet. On the second, a large financial holder deciding to sell did not change my view of what the underlying assets are worth.

Kayne Anderson manages the private investment fund that owns Sabinal Energy Operating, which received Mach units when Mach acquired Sabinal. After an April secondary offering, Sabinal reported holding about 15.5 million units. The September block therefore represented roughly half of that position. This was a financial holder reducing a large stake, not management selling its own units.

A seller accepting a discount to move that many units tells us something about its desire for liquidity. It doesn’t convey information about what Mach’s assets are worth.

My Mach thesis has not changed. As such, I’ve used the weakness in the units to buy for the Plutus portfolio.

What I Got Wrong About Q2 Results

The table below shows a quarterly comparison of Mach’s financial results. The quarter-over-quarter results are most relevant for Mach investors, as both quarters included a full-quarter contribution from the Sabinal and IKAV assets.

The quarter was weaker than I expected because I was wrong about an important mechanism.

In my June article, I assumed higher oil prices would flow fairly more directly through to cash available for distribution. They did not. Cash available for distribution fell to $60.1 million from $107.4 million in the first quarter, while development costs rose to $96.6 million from $75.2 million.

That $21.4 million increase in development spending mechanically accounted for about 45% of the decline in cash available for distribution. Higher oil prices reached revenue, but much of the benefit stopped at development spending.

That doesn’t mean management made the wrong decision. It means I underestimated what the capital reallocation would do to near-term distributable cash.

The Oil Pivot Has Yet to Show Up in Production

Mach’s ability to move capital between commodities remains one of the things I like about the business. CEO Tom Ward said that after the Iran conflict began, Mach shifted from drilling entirely for natural gas toward oil-heavy drilling, reversing the pivot it made after the tariff shock in April 2025.

Mach restarted the Oswego drilling program in May. Management says those wells target roughly 160,000 barrels of oil for about $3.3 million to drill and complete.

The problem is that the production benefit had not arrived by quarter-end.

Total production declined 5.5% sequentially to 148.9 Mboe/d, while oil production fell about 8% to 22.7 MBbl/d. Mach also deferred completion of its Mancos gas wells until 2027 to stay within its annual reinvestment framework. The second quarter therefore reflected the cost of changing direction while base production continued to decline.

The revenue mix improved because realized oil prices rose to $95.40 per barrel. But the improvement came from price, not additional oil barrels.

Watching the Reinvestment Rate

Management says Mach can keep production roughly flat while reinvesting less than 50% of operating cash flow. That claim is central to the thesis because a low reinvestment requirement leaves more cash available for distributions.

Second-quarter results do not disprove it, as management describes 50% as an annual framework, not a quarterly ceiling. But development costs equaled 62.9% of operating cash flow, and production still declined.

First-half production averaged about 153.1 Mboe/d. The midpoint of full-year guidance implies roughly 144 Mboe/d during the second half.

This is now the operating question I care about most. If Mach consistently needs materially more capital than management suggests merely to hold production flat, the economics of the business may be worse than I have assumed. If the second quarter instead reflected the timing of deferred gas completions and the lag before the restarted Oswego program contributes, production should begin to stabilize.

The next several quarters should tell us which explanation is right.

What I Am Paying for the Assets

At $10.52, I think the valuation compensates me for these problems.

Using roughly 166.9 million units outstanding and quarter-end net debt of about $1.13 billion, Mach’s enterprise value at $10.52 is under $3.0 billion. That is slightly below the $3.09 billion PV-10 of proved reserves reported at year-end 2025 SEC pricing. PV-10 is not fair value, but it is a useful reference point.

At that price, the units also trade at roughly 4.3 times trailing twelve-month Adjusted EBITDA.

By my calculation, cash return on capital employed was 16.5% over the trailing twelve months and 8.6% after development spending. Development capital is consistently slightly lower than depreciation, reducing concern that under-spending is inflating the return.

Alignment remains meaningful. Tom Ward reported beneficial ownership of about 8.4% of the units in May, and he and affiliated entities purchased 153,256 units at $13.05 in April.

Mach also says all 23 acquisitions since 2018 have met its requirement of buying cash-flowing assets at a discount to PDP PV-10.

Management has not yet demonstrated the deleveraging it believes is important. Net debt was about $1.13 billion at quarter-end, or roughly 1.6x trailing Adjusted EBITDA by my calculation, versus Mach’s stated long-term target of 1.0x.

The Risks I Am Watching Most Closely

Weak natural gas prices remain the biggest commodity problem for all natural gas producers, including Mach. The company realized just $1.93 per Mcf in the second quarter.

A fixed-price sales contract inherited with the IKAV assets requires Mach to deliver 64.5 Bcf of natural gas in 2027 at $1.72 per MMBtu, roughly 29% of a 620 MMcf/d annualized production base. Higher gas prices will help Mach, but not every molecule will receive them.

Oil hedges also limit near-term upside. As of August 1, Mach had 797 MBbl of Q3 oil swapped at an average $65.41 per barrel, plus another 184 MBbl under collars with a $60 floor and a $78.52 ceiling. At roughly second-quarter production levels, a little more than half of Q3 oil volumes remain outside those positions.

Mach’s credit agreement requires the company to hedge at least 50% of projected PDP oil and gas production over the next twelve months and 25% over months thirteen through twenty-four. Against second-quarter production, its oil hedges cover roughly half of volumes and its gas hedges about one-fifth. So part of the hedge book reflects lender requirements, not simply management’s view of commodity prices. Given Mach’s leverage, that protection makes sense, but it also limits the upside to cash flow when commodity prices rise.

The more serious risk is dilution. Mach has a $100 million at-the-market equity program, with proceeds intended primarily to repay borrowings. Through June 30, it had issued only about 129,000 units, raising $1.7 million gross. If management begins issuing meaningful equity at prices materially below intrinsic value, I would view that as permanent dilution and a direct challenge to my thesis.

The distribution can also fall again. It is the residual after development spending, coverage was essentially 1.00x this quarter, and management has said it would cut the distribution before selling assets.

What I Am Watching Next

I need to see the company’s oil pivot begin to show up in production, development spending stabilize volumes without consuming an excessive share of cash flow, and leverage move toward management’s stated target.

At $10.52, I think the market is giving me more than enough compensation for the leverage, commodity exposure, and questions the second quarter raised.

That is why I bought more.

Link to HFIR Energy Income Portfolio on RunPlutus.

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

The Trump administration appears to be days away from announcing measures to keep more diesel in the United States. An outright ban on exports looks less likely than it did earlier this week.

The idea moved quickly from speculation to a serious policy discussion after President Trump said on September 22 that he supported restricting diesel exports. The following day, however, the White House denied a Politico report that it was preparing a 90-day blanket ban, while Energy Secretary Chris Wright argued that an outright ban would not work. Wright said blocking exports could eventually force U.S. refiners to cut production, reducing supplies of gasoline and jet fuel along with diesel.

The legal path is also less straightforward than the headlines might suggest. In 2015, Congress repealed the provision that had expressly authorized the President to restrict exports of petroleum products. One plausible remaining route would be to declare a national emergency and invoke the International Emergency Economic Powers Act, which allows the President to regulate exports after declaring an emergency. The 2015 law did preserve a narrower power to restrict exports for up to one year in a national emergency or a Commerce-certified supply shortage. Still, that provision applies to crude oil, not refined products. According to the Politico report, the legal process for a ban was still being worked out.

The petroleum industry has also pushed back forcefully. Energy, refining, manufacturing and business groups have urged the administration to reject restrictions on fuel exports, arguing that they could reduce refinery utilization and ultimately leave the country producing less fuel rather than more.

None of this means the administration will do nothing.

Treasury Secretary Scott Bessent has said the administration is examining whether full or partial restrictions would work, while Wright has said the administration is working with refiners on a voluntary approach to increasing domestic diesel supplies.

No decision has been announced, but the options short of a ban are fairly well defined. The administration could ask refiners to voluntarily redirect cargoes to domestic buyers, which appears to be Wright’s preference. It could cap export volumes or require licenses for export cargoes, most likely under emergency powers. It could release the Northeast Home Heating Oil Reserve, which a bipartisan group of senators asked Trump to do on September 23. However, the reserve holds only about 1 million barrels, less than one day of recent U.S. distillate exports. It could also extend and simplify the Jones Act waiver that has allowed foreign-flagged tankers to carry fuel between U.S. ports since March. Each path would have very different consequences for refiners and for regional prices.

That is what I want to examine here.

Restrictions Could Lower U.S. Prices but Would Raise Them Abroad

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By: Jon Costello

GeoPark (GPRK) has changed considerably over the past year. Its operational outlook has improved, its growth opportunities have expanded, and the company’s potential value if management executes successfully is substantially greater than it was before.

The proposed acquisition of Venezuela’s Bare Block adds another dimension to that upside. Bare is a massive, already-producing resource with a relatively straightforward path to materially higher production over the next several years. Management believes the transaction could help take GeoPark from roughly $280 million of Adjusted EBITDA in 2025 to around $1.2 billion by 2030 at $75 Brent. Those numbers deserve to be taken seriously.

Despite the positives, more potential upside doesn’t necessarily make a stock easier to value.

The Old Valuation No Longer Fits

In January, I estimated that GeoPark shares could be worth roughly $21 if management delivered on its development plan, using a 3x EV/EBITDA multiple. At the time, I expected Vaca Muerta to be the company’s principal growth investment.

That framework no longer describes the company. On September 2, GeoPark agreed to acquire the remaining 95% of a holding company with rights to develop Venezuela’s Bare Block. The consideration is at least 42.1 million newly issued shares and could rise to 47.6 million, while Grupo Gilinski would emerge with more than 56% of the company and control it.

Bare could prove enormously valuable. But the transaction also significantly increases the share count, introduces a controlling shareholder, creates a new capital program, and adds a long-duration Venezuelan asset. I therefore no longer have enough confidence in my old $21 estimate to rely on it.

From Vaca Muerta to a Broader Capital Program

The broader scope of GeoPark’s capital program adds another layer of valuation uncertainty. Less than a year ago, the company’s growth plan centered on Vaca Muerta. In December, GeoPark projected $190 million to $220 million of 2026 capital spending, including $80 million to $100 million for Vaca Muerta.

Bare now adds another substantial, long-duration development program, and management has indicated that it may pursue further opportunities in Venezuela, Colombia and Argentina. GeoPark therefore has a broader—and potentially much larger—capital program than shareholders were evaluating less than a year ago.

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Since the start of 2026, I have written numerous times on the golden opportunities we are seeing in Colombia and Venezuela.

At the start of the year, the geopolitical scene was taken by surprise by the capture of Nicolás Maduro, Venezuela’s former president. Immediately following the news, I wrote a piece titled, “Venezuela Regime Change And The Impact On The Oil Market.”

This was followed by a piece a month later titled, “Venezuela’s Energy Sector Resurgence Is Happening Fast And The Investment Opportunities,” where I explained how the incoming law changes are very favorable for outside producers willing to take a chance on Venezuela.

Fast-forwarding to today, President Trump announced that the US has agreed to a deal with Venezuela on certain producing blocks.

The details haven’t been revealed yet, but based on recent press releases, some major players are about to get sizable producing blocks back (Chevron will be the most obvious first candidate).

Moving to Colombia, President Espriella took office on August 7, and he did not waste any time changing the makeup of Ecopetrol. The Ministry of Finance has called for an extraordinary shareholder meeting on September 15, and after an expected change to the corporate bylaws, Espriella will be able to nominate 6 additional board members, giving him total control of the board.

As the Ministry of Finance said in a post:

The National Government will present a slate of 9 names for the Board of Directors of Ecopetrol, with a clear mandate: produce more, regain trust, and advance the energy transition.

In order to achieve this mandate, Ecopetrol will need outside capital to 1) boost legacy oilfields, 2) unlock new reserves, and 3) improve efficiency. This wouldn’t be possible on its own, so this is essentially a call on independent producers to step into the fold.

Geopolitically speaking, Colombia and Venezuela are two of the more underappreciated areas in the energy sector (still).

Inflection Point

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By: Jon Costello

Note to readers: dollar figures are in Canadian dollars except where specified otherwise.

On Tuesday, August 4, Suncor Energy (SU) reported second-quarter results. The quarter featured some operational challenges, but the company’s performance was strong nevertheless.

The most significant challenge during the quarter was the weather. Fort McMurray received 50% more precipitation than its ten-year average, making it the wettest quarter in more than thirty years. Management estimates that the weather reduced bitumen mining production by 50,000 to 60,000 barrels per day.

Despite the reduced production, Suncor generated $5.329 billion of adjusted funds from operations, essentially matching the $5.345 billion record set in the second quarter of 2022, when WTI averaged US$108 per barrel. Adjusted funds from operations per share reached a record $4.52.

The quarter’s financial performance is impressive. It can be better appreciated when compared to the previous second quarters over the past few years.

In my previous Suncor article published in July, I raised the normalized 5-2-2-1 refining index assumption used in my valuation to US$35 per barrel and valued Suncor at approximately $97 per share. I also estimated second-quarter adjusted funds from operations of roughly $5.6 billion.

The quarter did not unfold as I expected. Upstream production fell 5.8% year over year, primarily because the planned turnaround reduced in situ bitumen production at Firebag. Higher production from Suncor’s oil sands mining operations, despite the unusually wet weather, partly offset that decline. Downstream throughput, meanwhile, reached a second-quarter record. Operating results relative to prior quarters are shown below.

The tables illustrate the benefit of Suncor’s integrated mode, as the mixed operating performance was still able to drive financial outperformance.

Chief Financial Officer Troy Little said downstream funds flow reached a record $2.3 billion. The company’s second-quarter report shows $2.299 billion, compared with $615 million a year earlier. The result was $172 million above the previous record in the second quarter of 2022 even though, after the renewable volume obligation, the New York Harbor 2-1-1 crack margin was more than US$10 per barrel lower.

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By: Jon Costello

Suncor Energy (SU) reports its second-quarter results on August 4, and the quarter should be exceptional. WTI averaged approximately US$95.65 per barrel from April through June, while refining margins reached levels exceeded only twice before, both in 2022.

I estimate adjusted funds from operations of approximately C$5.6 billion, compared with the C$5.345 billion Suncor generated in the second quarter of 2022. My estimate falls within a relatively wide range of C$5.2 billion to C$5.9 billion, but anything above the low end would likely represent a record.

That result will generate substantial cash for debt reduction, dividends, and share repurchases. However, a single strong quarter does not determine Suncor’s intrinsic value. The more important question is how much of the company’s current earnings power should be incorporated into a normalized estimate of cash flow.

I last valued Suncor’s TSX-listed shares at C$70 in December, when they traded near C$60. That estimate assumed US$65-per-barrel WTI over the longer-term due to the outlook for a sustained oversupply. It also assumed refining margins modestly above management’s guidance. The shares have since appreciated sharply, closing at C$87.53 on July 16.

I now believe Suncor’s normalized earnings power is higher than my December estimate. However, the change is attributable to the macro outlook and not any structural change in Suncor’s earning power.

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Neglect, dislike, or whatever you want to call it, investors in the energy sector are completely misreading the situation unfolding in Colombia. Following Abelardo de la Espriella’s victory on June 21, investors have seemingly responded to Colombian oil producers with a “meh”.

It doesn’t help that, since the start of Espriella’s rise in the polls, Brent has tumbled by ~35%, dampening enthusiasm for energy stocks. However, the investment community should pay closer attention to all the producers in the country, namely, the potential for more deals and exploration.

In particular, something very important came out today from Espriella’s Vice President, José Manuel Restrepo, in an interview with El Tiempo and Portafolio. This was his comment on Ecopetrol and on the state of Colombia’s oil and gas industry. I highlighted the most important part:

Regarding the issue of Ecopetrol, the vice president-elect pointed out that “it is very unfortunate. He has attacked it structurally and strategically (the current president, Petro) by preventing it from signing new gas and oil exploration contracts, by preventing unconventional exploitation in Colombia or abroad. He has attacked it operationally and financially, to the point that today, exploitation is more costly than it was 2 years ago. He has also attacked it in terms of corporate governance by intervening in decisions such as the one Ecopetrol had ready, and they threw it back after nearly 2 years of decision-making. And he has attacked it in reputational terms by keeping the current president in place.”

With that said, Restrepo stated that what needs to be done at Ecopetrol “from day 1 of our government is to call the assembly so that the assembly changes the board and the board of directors changes immediately. That is an immediate decision. I have no doubt that the assembly will be called. The assembly must change the board of directors and the board of directors must change the presidency of Ecopetrol as quickly as possible. Certain terms must be respected.”

The context is important to understand here because Colombia is the 5th largest oil producer in South America, and Ecopetrol, the national oil company, handles oil and gas contracts with independent oil producers. Every deal that gets signed needs to be vetted by Ecopetrol to some extent and by the Colombian government, which creates tedious delays and bureaucratic hurdles.

Under Petro (the left-wing current president), oil and gas exploration took a severe hit as he banned new E&P contract rounds and shortened long-term contract terms. In addition, Colombia’s gas reserves began to fall, making it more import-dependent, and its oil reserves now sit at just under 8 years at the current production of 734k boe/d.

This is not a situation you want to be in when you are an oil exporter. Colombia, under the left, was going to see oil and gas production fall in the coming years if capex didn’t increase meaningfully.

Political Godsend

It’s important to first understand the oil and gas deal structure in Colombia to give you a flavor of what to expect. Historically speaking, Ecopetrol has relied on outside capital to fund growth capex and increase total production. Deals are usually structured as follows:

• 50/50 split in production sharing, the operator partner gets 50% of the production.

• Capex is usually weighed on the operator partner first, and then split 50/50 later, or in some cases, it is just paid for by the operator partner.

• Royalty is charged on the 50% production piece of the operator, so Colombia benefits from 1) the capex spent by the operator and 2) the royalty payment made.

From Ecopetrol’s standpoint, which is majority-owned by the Colombian government (88.49%), the capex spend gives it optionality for production upside and exploration potential. The royalty payment maximizes cash flow, and the even split in production gives the operator every incentive to increase production as much as possible.

It’s a win-win deal.

But under Petro, Ecopetrol suffered because 1) he banned exploration and 2) he vilified oil and gas and pivoted the economy towards renewables.

Now that he’s gone, Ecopetrol will embark on a new era of exploration and deal-making. There are 4 years of pent-up demand for deals that have been sitting in the back office, cluttered by bureaucracy. For the sake of due diligence, we have hired on-the-ground political consultants to inform us about the labyrinth we need to navigate in such a hostile political environment, and let me just say that it is more torturous than poking your own eyes with needles.

Under Espriella, his campaign was pro-hydrocarbons. He wants to restart oil and gas exploration, something Petro banned. He wants to issue new contracts, allow responsible fracking, offshore Caribbean oil and gas, and push Ecopetrol’s reserves higher. He stated in his campaign that he wants to push Colombian oil production from ~734k boe/d to 1.35 million boe/d. That’s not possible without the support of other operators, as I explained above.

What does that mean for oil producers?

Parex Resources (PXT.TO) is now the largest independent oil producer in Colombia. It has become the behemoth primarily through deals with Ecopetrol and exploration contracts through the previous administration. Espriella’s presidency will put Parex squarely in the center as one of the key producers to take advantage of what’s to come.

Geopark (GPRK) is also extremely well-positioned to capitalize on new deals. One key issue for both Parex and Geopark was that during the Petro administration, the lack of new exploratory contracts made it very difficult to expand oil reserves. Following the production sale by Fronterra Energy, formerly known as Pacific Rubiales (more on this later), Parex emerged as the largest independent oil producer, forcing Geopark into Argentina and Venezuela.

I suspect Geopark will make an aggressive move back into Colombia now that the administration is favorable towards signing new oil and gas contracts.

What about Ecopetrol?

Well, I am reluctant to give it my blessing here, considering that the inner workings of a national oil company are inherently slow and inefficient. I suspect Ecopetrol will need to rely more on independent oil producers to execute rather than executing itself. In addition, as Jon covered in January, the valuation on Ecopetrol shares is not attractive relative to the others.

Now, for readers, you will have noticed a trade alert today that I bought more shares of New Stratus Energy (NSE.V). On paper, NSE does not have producing assets in Colombia yet, but the company announced in its year-end reports that the Colombia deal was expected to close towards the end of May. But from what I understand, political events made it difficult for a national oil company to finish deals.

From my understanding, the runoff presidential election results, which ended on May 26, saw Espriella, a right-wing candidate, surge to the top. Iván Cepeda, the candidate supported by Petro and favored going into the election, quickly fell behind. Because of this political backdrop, it is difficult for national oil companies to announce any changes to their existing operations for fear of political backlash, especially if the right-wing candidate wins.

Following the election results on June 21, where Espriella won, the president-elect immediately demanded that Ecopetrol’s board and CEO be replaced as his first decree. This meant that anything the national oil company does from now to August 7th will be heavily scrutinized, even if the existing due diligence was already in place.

But given everything I wrote here about how favorable Espriella will be to the oil and gas industry, I believe today’s sell-off presented an excellent opportunity to add to our position. The comments from the Vice President today about how the first order of business is to call for an extraordinary shareholder meeting, followed by execution of oil and gas contracts that have been months/years in the making, is the most bullish signal one needs to understand the situation that we are in.

And for NSE specifically, JF Arata, CEO of the NSE, is well-positioned to capitalize on the upcoming deal boom in Colombia. He was a co-founder of Pacific Rubiales, which was at one point the largest independent oil producer in Colombia. JF was also responsible for developing the Rubiales oil field, the largest heavy-crude deposit in Colombia. The operational team that was formerly at Pacific Rubiales joined JF when they started NSE.

This is why, from an execution standpoint, I believe the team can execute, but we just need to survive the myriad of political labyrinths required to land deals in South America.

I hope this explains my logic and my bullishness on Colombian oil producers.

Conclusion

I believe investors are still misreading the sentiment in Colombia largely due to the fact that it is 1) underfollowed, 2) unloved, and 3) in the energy sector. The recent sell-off in oil prices did not help, but I think this seismic political change will give the Colombian energy sector a major boost.

We plan to allocate to both Geopark and Parex tomorrow, in addition to our exposure in NSE. I think this is where the undervaluation is if you are looking for upstream oil producers.

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

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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