By: Jon Costello

SLB, N.V. (SLB)—formerly Schlumberger, Ltd. before its name change in 2022—is a diversified international oilfield services company domiciled in Curacao that provides a suite of services across the life of an oil and gas field. The company’s customers include national oil companies, integrated oil and gas majors, and independent producers worldwide. It reported $35.7 billion in revenue in 2025 and employs 109,000 people in more than 100 countries.

Its operating segments are shown below.

SLB is positioned for the next 10 years to be better than the previous 10. However, the company’s long-term track record doesn’t inspire confidence. Over the past 20 years, SLB shares have returned 1.5%, including dividends, badly lagging the S&P 500’s 11.1% return over the same timeframe.

The stock’s performance is attributable to SLB’s repeatedly poor execution and capital allocation. At the moment, I see little reason for that to change, which dims my view of its prospects over a full cycle and its ability to sustainably grow intrinsic value per share.

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By: Jon Costello

The recent rise in interest rates has led me to reassess yields available in midstream equities. On October 19, the 10-year Treasury yielded 5.14%, more than 100 basis points above its February level.

I have therefore been reviewing some of my longstanding holdings with greater attention to the risks that could undermine my investment theses. I want to consider what could go wrong, even with businesses I know well. I began with Enterprise Products Partners, L.P. (EPD), an important income holding I have recommended for years, including as recently as February.

The issue is whether EPD’s 6.1% distribution yield is attractive when 10-year Treasury securities yield about 5.1% without credit risk. Does distribution growth make the difference?

After this review, I will keep my units for income, but won’t add at the current price of $39. My assessment of EPD’s financial strength remains intact, but its valuation no longer supports additional buying.

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By: Jon Costello

The spate of deals in the North American energy patch raises the question of whether producers are scrambling to lock up drilling inventory before it runs out. The latest two deals, announced yesterday, might be read that way.

Nevertheless, I think EQT’s (EQT) proposed all-stock acquisition of Range Resources (RRC), valuing Range at about $13 billion, and Ovintiv’s (OVV) agreement to buy Montney producer Logan Energy (LGN:CA) for about $890 million in cash, have unique rationales. Neither buyer was under pressure to add inventory, while each bought something specific. Operationally, at least, both deals make sense. Whether the prices were right, and whether management delivers, are questions for standalone articles. This is my quick take.

Ovintiv: Oil-Weighted Barrels and Locations Next Door

What is clear is that Ovintiv did not need Logan. When Ovintiv bought Paramount Resources’ Montney assets in 2024, it said the deal extended the life of its premium Montney oil and condensate inventory to approximately 15 years. Logan’s impact is far smaller. It would add approximately 220 additional premium Montney locations, which Ovintiv defines as earning internal rates of return above 35% at $55 per barrel WTI and $2.75 per MMBtu gas. At the company’s 2026 Montney pace of 130 to 140 net wells, Logan would represent roughly 19 to 20 months of drilling. Because the deal is small enough for Ovintiv to fund with cash and existing borrowing capacity, with no new shares, it can be considered a bolt-on, not a necessity.

What Logan offers Ovintiv is the right kind of production and acreage. Its roughly 20,000 boe/d is about 40% oil, condensate, and NGLs, compared with 27% liquids for Ovintiv’s Montney production in the second quarter. Logan’s 7,000 bbl/d of oil and condensate is equal to approximately 8% to 9% of the 80,000 to 85,000 bbl/d Ovintiv expects from the Montney in the second half. Its 266,000 net acres sit in the Montney oil window, including about 200,000 core acres, 80% of which are undeveloped.

That kind of acreage is getting harder to find. Enverus estimates that the Montney’s high-liquids regions hold about 30 years of inventory at current drilling rates, compared with about 90 years for lean gas, and that about 25% of the economic condensate-window inventory changed hands in under 18 months.

Ovintiv also expects to run the assets more efficiently than Logan had. The acreage sits near Ovintiv’s existing operations, and Ovintiv expects to cut more than $2 million from the cost of each well, bringing Logan’s costs in line with its own Montney wells and putting the deal’s total annual cost savings at around $60 million.

Logan also brings two new oil batteries at Simonette, one running and one due by the end of the first quarter of 2027, with 24,000 bbl/d of combined capacity, more than three times its current oil and condensate output, plus stakes in two gas plants. Ovintiv CEO Brendan McCracken says the assets “have demonstrated leading oil productivity performance” and “will immediately compete for capital” with the rest of the company’s portfolio. Ovintiv expects the deal to add about 5% to cash flow per share in 2027 and has left its shareholder-return targets unchanged.

EQT: Adding Scale to Serve Large Buyers

EQT was also not running out of inventory. While the company doesn’t disclose a standalone figure, a third-party analysis by Novi Labs estimated in May that EQT held approximately 18 years of Marcellus inventory, including roughly 15 years of locations that break even below $3.50 per Mcf at its 2026 drilling pace, before counting its Utica acreage. Adding Range would lengthen that runway. EQT says the combined company will have more than 30 years of inventory across nearly 3 million net acres, and that the deal allows it to accelerate development of that inventory into contracted, demand-led growth. The two estimates use different methods, but it is clear that EQT is buying duration to support growth, not scrambling to replace its production.

Nor was Range a distressed seller. It ended June with about $881 million of net debt, and its shareholders will own about 27% of the combined company. CEO Dennis Degner says Range’s board determined that the deal will enhance shareholders’ “ability to participate in a constructive long-term natural gas and NGL macro outlook.”

More importantly, the addition of Range allows EQT to build scale. Range produced 2.30 Bcfe/d in the second quarter, approximately one-third of EQT’s roughly 7 Bcfe/d, bringing the combined company to more than 9 Bcfe/d. EQT says the deal will give it the largest natural gas marketing platform in the U.S., with more than 10 Bcf/d of marketing capacity, more than 3,700 miles of pipelines and more than 40 Bcf of gas storage, along with an unlevered free cash flow breakeven below $2 per MMBtu.

Scale and duration will allow EQT to better serve the large natural gas buyers prized by gas-weighted E&Ps. In July, EQT reported a 10-year agreement to supply 325,000 Dth/d to Competitive Power Ventures’ new 2-gigawatt Shay Energy Center in West Virginia, priced off PJM power prices, and a five-year LNG offtake agreement with a large Asian integrated energy company for 0.5 million tonnes a year starting in 2028. These buyers want a supplier that can commit large volumes for a decade or more, and Range will add both the volumes and the years.

Range also brings more liquids-rich production, although the combined company will still be approximately 88% gas. Range expects liquids to exceed 30% of its 2026 production, and in the second quarter it realized a record NGL premium of $3.49 per barrel over Mont Belvieu, which it attributed to access to international markets. EQT expects $325 million of annual cost and marketing benefits within two years, with a path to more than $600 million that includes wider marketing margins.

Rational Consolidation

When compared side by side, these two deals have little in common beyond their announcement date.

Ovintiv bought oil-weighted production and premium oil-window locations next to infrastructure it already operates. EQT bought scale, inventory duration, liquids exposure, and the capacity to commit supply to large, long-term customers. Neither buyer was running out of inventory, and both had conservative balance sheets, with Ovintiv expecting net debt below $4 billion after closing, and EQT expecting BBB-quality credit metrics at closing and leverage of 0.6x by the end of 2027.

That makes this round of consolidation rational, at least from an operational perspective. Price and execution are open questions. EQT is paying a 20.6% premium and Ovintiv is paying approximately $1.5 million per premium location. Whether the promised savings arrive will determine whether either price was justified, and I will take those questions up in separate articles.

My view is that operating logic, not fear of running out of inventory, drove both deals. More deals may follow, but I don’t regard these deals in themselves as a signal of a looming consolidation wave.

Link to HFIR Energy Income Portfolio on RunPlutus.

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

By: Jon Costello

Crude tanker rates have reached levels that would have been difficult to imagine a year ago. On October 9, the Baltic Exchange, which publishes benchmark shipping rates based on assessments by shipbrokers, estimated that a VLCC traveling from the Middle East Gulf to China could generate a round-trip time-charter-equivalent return of $1.41 million per day. While this assessment is a benchmark, not what the average owner earns, it illustrates how extraordinary the market has become. According to the EIA, tanker rates hit record highs in September.

I question how long these conditions can last. The EIA expects most Middle Eastern oil production to recover to pre-conflict levels by the end of the second quarter of 2027, while the IEA forecasts a 2.6 million-barrel-per-day decline in global oil demand this year and an eventual surplus in 2027. Both forecasts are subject to significant uncertainty. Neither agency forecasts tanker rates, but a return to more normal shipping patterns could release substantial vessel capacity and put pressure on freight rates.

I’ve examined ten publicly traded tanker owners to determine how a decline would affect their earnings, financial positions, and valuations. Their stocks have appreciated together, but I don’t believe their shareholders face equal risks. My concern isn’t that tanker companies are earning too much money today. It’s that investors may be paying prices that assume a substantial portion of these earnings will continue, when the conditions producing them could prove temporary. That is the risk I want to examine.

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By: Jon Costello

I got Hess Midstream (HESM) wrong. There is no way around it.

I bought HESM on April 29, 2021, at $23.42 and sold it on February 9, 2023, at $29.36, thinking it was fairly valued then. In August, I revisited the company and estimated its intrinsic value at $44 to $50 a share. I expected capital spending to decline sharply, allowing considerably more of the company’s earnings to become free cash flow. A possible buyout by Chevron (CVX) offered additional upside.

I recognized one risk. Chevron might eventually reduce the tariffs it paid HESM or direct production elsewhere. But I assumed that would become a serious concern after the existing contract terms ended in 2033. On October 6, Chevron announced an agreement that cuts its Bakken midstream costs beginning in 2027. I underestimated what Chevron could obtain from HESM while the contracts were still in place.

The shares closed at $32.26 on October 9, down 16.6% from their October 6 close of $38.69. That decline doesn’t convince me they are cheap. The transaction leaves public shareholders with lower earnings, more leverage, and little prospect of the distribution growth I expected. I would not buy the stock at that price, and if I owned it, I would consider selling.

What Chevron Gets

Chevron is giving up its interest in HESM, including control of the general partner, and contributing midstream assets in the DJ Basin. The assets include gathering and storage facilities and a 20% interest in the Saddlehorn pipeline. In return, HESM will cancel about 78.3 million Chevron-owned shares and equivalent units, reducing the number of economic interests outstanding by almost 40%. It will also pay Chevron $200 million, subject to a working-capital adjustment, principally using its credit facility. The transaction has not yet closed; the companies expect to complete it by year-end.

Source: Hess Midstream, Investor Update Call, October, 2026.

For Chevron, the most attractive part is the reduction in the fees it pays to move and process its Bakken production. Chevron estimates that its midstream cost per unit will fall by roughly 50%. It also plans to reduce its Bakken drilling program from three rigs to two. HESM receives another set of assets, a smaller share count, and longer commercial agreements, but gives up substantial revenue from its largest customer.

An independent conflicts committee approved the terms after receiving financial and legal advice. I have no basis for suggesting the agreement was improper. But Chevron was negotiating from a position of considerable strength, and the outcome seems much more favorable to Chevron than to the shareholders who will remain in HESM.

What Public Shareholders Give Up

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By: Jon Costello

At HFIR, my job is to find ideas with asymmetric payoffs and a high margin of safety. During times like these, I find myself in an uncomfortable situation.

People subscribe because they expect something of value, usually investment ideas they can act on. I understand that expectation, and I feel an obligation to meet it. But while I can produce investment commentary whenever I choose, I can’t produce attractive investment opportunities on demand. The two aren’t the same thing.

I’ve managed other people’s money professionally since 2007. I consider myself an investor first, and writing about investments is an extension of what I do. Writing helps me organize my thinking and forces me to explain why I believe a stock is worth buying, or why it isn’t. I want this service to succeed, but building a large subscriber base has never been an end in itself. I’m certainly not going to change the way I invest to attract or retain subscribers.

I spend a great deal of my time searching for stocks trading at substantial discounts to intrinsic value. I investigate neglected companies, explore industries that receive little attention, and look for angles on familiar businesses other investors may be missing. I enjoy the search, even when the work leads nowhere. But lately, that’s where an awful lot of it has led. I keep looking and coming up empty-handed.

What’s unusual about the current situation is that it’s the first prolonged shortage of bargains I’ve experienced since starting this service in 2020. For most of the past six years, I’ve managed to find a fairly steady stream of attractive opportunities, particularly among oil and gas midstream companies. Many of those investments worked out well.

Consider how much things have changed. In late 2020, Enterprise Products Partners (EPD) offered a distribution yield of more than 8%, while the 10-year Treasury yielded less than 1%. Today, EPD yields around 6%, while the Treasury offers more than 5%. The investment proposition has changed considerably. Many of the stocks that once offered unusually attractive returns have appreciated, leaving far less room for further gains.

Meanwhile, I’ve been through enough periods like this during my investment career to know how frustrating they can be. I want to find bargains just as much as subscribers want me to find them. But I can’t make them appear simply because I’m looking for them.

So what am I supposed to do? I could relax my standards a little. I could recommend stocks that look reasonably priced instead of genuinely cheap, or turn every company I investigate into a potential buy. That would give me more to publish and make the service look busier. It would also defeat the purpose of doing this in the first place.

I suppose some of the value I can provide subscribers during periods like this is to demonstrate that investors should be comfortable doing nothing. Sometimes it’s best to build cash, take profits on stocks that have become expensive, and wait for better opportunities. That doesn’t mean I should stop researching companies or sharing what I find. But I see no reason to recommend an investment simply because subscribers expect another stock pick.

In fact, I would argue that someone who receives few or no new recommendations for several months may be getting better advice than someone whose investment service delivers five new picks every month. The number of recommendations tells you nothing about their quality. When bargains are scarce, forcing a steady stream of ideas may do more harm than good. I’d rather disappoint subscribers by saying I haven’t found anything worth buying than encourage them to put money into stocks I wouldn’t buy myself.

Of course, I have to consider the possibility that the problem lies partly with me. Perhaps I’m anchored to the valuations available a few years ago, or I’m spending too much time looking in industries where bargains used to be plentiful. I may be overlooking opportunities elsewhere. That’s something I have to keep questioning as I investigate new companies and industries. I’m not suggesting there are no attractive investments anywhere. I’m saying that I haven’t been able to identify many that I understand well enough and that are cheap enough to justify putting capital behind them.

I don’t expect this situation to last forever. I’ve seen enough market cycles to know that bargains tend to arrive in clusters. An industry falls out of favor, the economy weakens, or investors become pessimistic, and suddenly opportunities appear that weren’t available a few months earlier. I have no idea when that will happen again, but I intend to be ready when it does.

We experienced one of those periods in 2025. I established oversized positions in Valaris (VAL), Transocean (RIG), Calumet (CLMT), Warrior Met Coal (HCC), and several other companies, some of which subsequently more than doubled. I didn’t expect those investments to appreciate as quickly as they did. But at the prices available, I considered them about as close to no-brainer investments as I’m likely to find. I committed substantial capital because I believed the potential rewards more than justified the risks.

I expect to find similar opportunities again, although I can’t say when. Nor can I promise that the next group of stocks I recommend will double. What I can promise is that I won’t recommend an investment unless I believe its prospective return justifies the risks. I can’t control what opportunities the market offers or how an investment ultimately turns out, but I can control the standards I apply before committing capital. When bargains return, subscribers will read about the investments I make, just as they did in 2025. I believe access to that work can be worth considerably more than the price of a subscription.

What I’m offering is a running account of an investor plying his craft. Sometimes several new investments will come in a relatively short period. At other times, I’ll spend weeks or months researching and buying almost nothing. I intend to follow opportunities at my own pace and exercise my own judgment, regardless of whether that satisfies the demands of a subscription business.

I recognize that this approach may disappoint some subscribers, and perhaps even cost me a few. That’s a risk I’m willing to take. I’d rather lose a subscriber than compromise my investment standards to keep one.

I’m an investor first. The writing follows from that, not the other way around.

Link to HFIR Energy Income Portfolio on RunPlutus.

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

By: Jon Costello

Less than a year after buying MEG Energy, Cenovus Energy (CVE) has agreed to acquire Athabasca Oil (ATH:CA). At first glance, I can see the attraction. Athabasca owns a large oil sands resource base, with years of potential development ahead. But oil in the ground is only part of what Cenovus is buying. It will take time and substantial capital to turn much of it into production. I examined the terms, the cash flow Cenovus can expect, and the price it is paying for those future barrels. For Athabasca shareholders, this looks like a good exit. For Cenovus shareholders, I am much less enthusiastic.

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By: Jon Costello

Previous article on Transocean’s acquisition of Valaris.

I remain long Transocean (RIG) and Valaris (VAL) for myself and clients. Since I last reviewed the position, an important source of risk has been removed.

On September 30, Transocean and Valaris disclosed that the Justice Department’s Antitrust Division had closed its investigation of the merger under the Hart-Scott-Rodino Act and that the waiting period had expired. CFIUS had already cleared the transaction in June. The companies now expect the combination to close in the fourth quarter, subject to the remaining conditions.

These developments do not mean the deal is complete. The definitive joint proxy statement has not yet been filed, so shareholder approvals remain outstanding, as does the Bermuda court process required for the scheme of arrangement. Brazil’s CADE review was publicly notified in July, and I found no published decision as of October 1.

With U.S. antitrust risk reduced, the focus shifts to execution. The questions now are whether the deal closes, whether management can integrate Valaris without losing the expected cost savings, whether debt comes down, and whether stronger offshore pricing eventually translates into higher free cash flow for shareholders.

The U.S. Antitrust Risk Has Now Receded

The Justice Department’s decision deserves more weight than the routine expiration of an initial HSR waiting period.

Transocean and Valaris first filed under the HSR Act on March 2. Transocean withdrew its filing on April 1 and refiled on April 3. On May 4, the Justice Department issued a Second Request, requiring additional information and extending the review.

On September 30, the companies disclosed that the Antitrust Division had closed its investigation and the HSR waiting period had expired. The filing did not disclose a divestiture, consent decree or other remedy. CFIUS had already provided written clearance on June 29.

The latest filing says the companies expect a fourth-quarter close, subject to the remaining conditions. But the risk profile is plainly different from what it was a month ago. A U.S. antitrust challenge was one of the most visible obstacles to the transaction. That obstacle has now receded.

If the deal were to fail for another reason, I would still want to own Transocean. The deepwater thesis predates the agreement to acquire Valaris, and Transocean was already making progress on its balance sheet. Net debt declined to $4.31 billion at June 30 from $4.52 billion at March 31. Losing Valaris, however, would remove what I view as the clearest path to accelerating that improvement.

Contract Visibility Has Strengthened

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By: Jon Costello

Five years ago this month, I wrote that real interest rates were so deeply negative that they “would have to increase several-fold to reflect the reality of a sustained inflationary environment.” That week, the 10-year Treasury yielded 1.61%. On Monday, it closed at 5.31%, its highest level since May 2002.

The bond market has now done what I thought it eventually would, while the stock market has not fully adjusted. I am not predicting a selloff. Higher interest rates tell me very little about where the S&P 500 will trade next month. They do, however, tell me what I should be willing to pay for every investment I consider, and today the answer is less than what I would have paid when the 10-year yielded 2%.

That applies directly to the energy-income securities we own and consider for the HFIR Energy Income Portfolio. For most of the post-financial-crisis period, those securities competed against an unusually weak alternative. Today, investors can earn more than 5% from the U.S. government without taking business risk, although longer-dated Treasuries still carry interest-rate risk. That raises the hurdle rate for everything else.

What Has Changed

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By: Jon Costello

I’m no expert on the tanker market, but the prospect of U.S. diesel export restrictions struck me as creating a logistical effect the market might be underappreciating and therefore worth investigating.

The obvious conclusion might be that fewer U.S. diesel exports would mean fewer tanker voyages and lower rates. But Europe and Latin America would still need diesel. If Gulf Coast barrels disappeared, some buyers might have to replace them with cargoes traveling much farther from refineries in Asia or elsewhere. After all, tanker demand depends not simply on how many barrels move, but on how far they travel.

That led me to Scorpio Tankers , whose 75-vessel product-tanker fleet includes 36 MRs, 25 larger LR2s and 14 Handymaxes. An export curb would eliminate some U.S. voyages and could pressure rates, particularly for MRs serving shorter Atlantic Basin trades. The question was whether longer replacement voyages could create enough tanker demand to offset those lost cargoes.

I found that anything that materially reduces U.S. exports would likely be a near-term negative for Scorpio because the lost cargoes are more certain than any potential replacements. Consider that U.S. distillate exports were substantial, averaging 1.56 million barrels per day in the four weeks ended September 18. The EIA category is broader than diesel, but in June about three-quarters went to Latin America and the Caribbean, led by Mexico and Brazil, while Europe took only about 16%. An export restriction would therefore eliminate existing tanker voyages before any benefit from longer replacement routes developed.

Scorpio’s Operating Model

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Six months ago, the war with Iran sent oil prices sharply higher. We have now entered the period when history says U.S. oil production should begin responding.

The next several months will test the argument I made in late August about the geology behind slowing U.S. shale growth. If $90 to $100 oil cannot produce much more U.S. supply, the longer-term oil market will look very different.

Why Production Takes Time to Respond

The EIA has long estimated that oil rigs follow changes in WTI prices with a lag of about four months, while production follows the rigs about two months later. That puts the historical lag from a significant change in oil prices to production at roughly six months.

The reason is straightforward. Producers must decide that higher prices justify more investment, contract rigs and crews, drill and complete wells, and connect them to pipelines. Even shale cannot respond overnight.

Six months is only a rule of thumb. After oil prices peaked in June 2014, U.S. production kept rising for another 10 months. After prices bottomed in February 2016, production kept falling for seven. Those episodes point to a response to this year’s price increase between September and December. We are at the beginning of that window, not the end.

The table below compares those episodes with this year’s. It also shows how modest this year’s drilling response has been. In the four months after drilling bottomed in 2016, the oil rig count rose 30% with WTI averaging about $46 per barrel. In the four months after April of this year, it rose only 10% with WTI averaging about $88.

The Price Signal Has Been Hard to Miss

WTI averaged $64.51 per barrel in February, then $91.38 in March, $100.32 in April and $102.13 in May.

Drilling responded, but not dramatically. The U.S. oil rig count rose from 407 at the end of February to 455 last week, an increase of 48 rigs, or about 12%. That is meaningful, but hardly the drilling boom we might have expected historically from oil approaching $100.

Official production data run only through June, so it is still too early for a verdict. June production was 13.79 million barrels per day, compared with 13.73 million in March. HFI Research’s real-time production tracking, which has been a useful leading indicator, shows production creeping higher since then, but not by anything approaching what we might have expected after a roughly 50% increase in WTI.

Producers Are Sending Us a Message

One explanation is that producers simply do not believe today’s prices will last.

The futures curve is a notoriously poor predictor of where oil prices will actually trade. But producers need a basis for planning, and in the absence of a reliable forecast, it becomes a de facto reference point. It also determines the prices at which they can hedge future production.

On September 24, WTI for December 2027 delivery traded at $73.72 per barrel, compared with $94.61 for delivery this November. Producers therefore have little reason to assume that $90 to $100 oil will persist over the life of a new well.

The Kansas City Fed found the same skepticism. Producers surveyed in July said they needed WTI of about $83 per barrel to justify a substantial increase in drilling, yet expected only $75 six months later.

The industry itself may also have changed. Consolidation has shifted more production into larger companies focused on capital discipline and shareholder returns. Producers have also been steadily consuming their best drilling inventory, leaving fewer of their most prolific and profitable locations.

It’s Now or Never

I am less interested in whether production rises than in how much.

After U.S. production bottomed in September 2016, it increased by about 0.6 million barrels per day over the following six months and by nearly 1 million over the next year, even though WTI averaged only about $49 per barrel. Oil has averaged more than $80 every month since March. A comparable response from today’s roughly 13.8 million barrels per day would put production near 14.4 million by next spring.

If production is moving toward that level, shale will have shown it can still respond to higher prices. If it remains near last October’s record of just under 14.0 million barrels per day around year-end, I think we should begin changing how we think about the U.S. oil industry. The EIA’s own forecast, about 14.0 million barrels per day in the fourth quarter and 14.3 million on average next year, falls short of that pace.

A much later drilling response looks less likely. The oil rig count reached 452 in mid-July and has remained between 447 and 455 since, despite WTI averaging more than $80 every month. Much of the production we will see through early next year is therefore being drilled now. If oil falls toward the low $70s next year, producers that added relatively few rigs at $100 are unlikely to become more aggressive.

What It Would Mean for the Oil Market

U.S. crude production rose from 5.5 million barrels per day in 2010 to 13.7 million last year, an increase unmatched by any other country. Shale became the world’s most important source of incremental oil supply because higher prices could bring additional barrels to market relatively quickly.

A world in which that mechanism becomes materially less responsive is a different oil market.

Brazil, Guyana and Canada will continue adding supply. The EIA expects the three to add roughly 0.4 million barrels per day next year. OPEC also retains spare capacity, although nearly all of it is currently stranded behind the closed Strait of Hormuz. EIA expects about 2.4 million barrels per day of spare capacity to be available once flows normalize, compared with about 3.0 million at the end of 2025.

If global demand eventually resumes growing by roughly one million barrels per day annually while U.S. production adds little, the call on those remaining sources rises quickly. On static assumptions, the 0.6 million barrels per day not covered by Brazil, Guyana and Canada each year would absorb a 2.4-million-barrel-per-day cushion in about four years. Of course, reality will not be that neat—demand, capacity and production elsewhere will change—but the arithmetic shows how much more dependent the market would become on OPEC without continued U.S. growth.

The path would not be smooth. A reopened Strait of Hormuz could send oil prices sharply lower next year, and a recession would reduce demand. But over a period of multiple years, slower U.S. production growth would leave the market with a smaller margin for error. Outside OPEC, no other source combines the scale and short-cycle responsiveness that U.S. shale brought to the market over the past decade.

Of course, I could be wrong. In 2022, the oil rig count rose only about 20%, yet U.S. production increased by 1.8 million barrels per day over the following 21 months as producers extracted more oil from each rig. If production is moving toward 14.4 million barrels per day by next spring, I will have significantly underestimated shale.

For our HFIR Energy Income portfolio, a weak shale response would strengthen the multi-year case for the energy businesses we own. By contrast, a strong response would leave us relying more on each company’s own merits rather than a structurally tighter oil market.

Six months ago, the market gave U.S. producers an unusually strong incentive to drill. Now we get to see how much oil they can deliver.

Link to HFIR Energy Income Portfolio on RunPlutus.

Analyst’s Disclosure: I/we have a beneficial long position in the shares of the HFI Research Energy Income Portfolio 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

I want to continue a theme I have discussed recently: elevated stock market valuations are making it more difficult than usual to find attractive investments, even within the sectors and industries I know best.

I remain constructive on the longer-term outlook for oil, but many of the energy companies I would most like to own no longer look particularly cheap. Using roughly $80 per barrel WTI as a reasonable mid-cycle assumption, a number now trades around my estimate of intrinsic value.

That prompted me to look more broadly. Given how difficult it has become to find energy companies offering the margins of safety I am looking for, I expected Energy to have become relatively expensive compared with other parts of the market.

What I found surprised me. Energy was still the cheapest major S&P 500 sector on expected earnings and remained among the least expensive on other valuation measures. If a sector that no longer looks particularly cheap to me on normalized assumptions still ranks among the market’s cheapest, that says something about valuations elsewhere.

Editor’s Note: Free subscribers can use the 1-time unlock feature to read this article.

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By: Jon Costello

I’m increasingly befuddled by the stock market’s continued strength.

I look at the risks building in the energy market, consider what prolonged shortages and higher fuel prices could do to the economy, and then look at market valuations that seem to leave little room for disappointment. I cannot reconcile the two, and it has been gnawing at me for weeks.

I’m not arguing that markets have to fall, or that I have weighed every risk correctly. But when I consider how much has to go right at today’s valuations—and how many troubling developments in the energy market would have to reverse—the market’s confidence gets harder to understand by the day.

My concern is that the longer the energy supply disruptions persist, the greater the risk that the damage spreads beyond oil and into the broader economy. At the very least, that possibility seems increasingly difficult to dismiss.

I want to explain what concerns me and, more importantly, how it is influencing my decisions. For now, I remain constructive on selective energy investments, comfortable holding cash, and focused on researching businesses I would want to own if a substantial decline creates better prices. I would rather decide what I want to own and what I would be willing to pay before falling markets make those decisions more urgent.

Less Room to Absorb Another Disruption

The oil market has less room to absorb another disruption than it did even a few weeks ago. Supply losses persist while the inventories that absorbed earlier disruptions continue to be drawn down.

Last week’s attacks shut Saudi Arabia’s East-West pipeline, a major route for moving crude to the Red Sea without transiting the Strait of Hormuz. Reuters reported that export-ready stocks at Yanbu could cover only five to seven days and that a persistent outage could put 4% of global supply at risk. By September 15, Reuters reported Saudi Aramco had canceled some European cargoes. The timing of a restart remains uncertain. Five to seven days is not much of a buffer, yet the market seems to be treating it as another routine supply headline.

The pipeline has been especially important because shipping through Hormuz remains constrained. Losing that alternative route makes it harder for Saudi Arabia to restore reliable exports even if crude is available.

On the inventory front, the IEA’s September Oil Market Report estimates that observed global oil inventories fell by 507 million barrels from February through August, an average draw of 2.8 million barrels per day. It forecasts 2026 supply averaging 100.7 million barrels per day, with Middle Eastern supply not fully recovering until 2027.

The SPR provided another important buffer, and much of that has now been used as well. The SPR held about 285 million barrels at the end of the week of September 4, down from roughly 398 million barrels at the end of April. That is a decline of more than 110 million barrels in a little over four months. Much of the oil was released through exchanges, which means those barrels must eventually be returned to the reserve along with additional barrels as a premium. While the exchanges helped relieve the immediate shortage, they did not create new supply. They simply shifted some of the burden into the future, while leaving considerably less oil in the reserve to respond to another disruption.

Industry leaders are highlighting these developments. Chevron (CVX) CEO Mike Wirth warned that the crude-oil buffers that moderated earlier price increases were largely depleted.

Taken together, these conditions leave the market with less ability to absorb additional supply losses without either a simultaneous supply recovery or higher prices that force demand lower.

Economic Risk Is Growing

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By: Jon Costello

In 2024, I argued that Headwater Exploration (HWX:CA) deserved a steep premium to Tamarack Valley Energy (TVE:CA). I pointed to Headwater’s economics, operating track record, long-term growth prospects, and the management team led by Neil Roszell.

I bought Headwater in 2020, before the company had established the operating record investors would later come to value, and held it until 2024. The high quality of management was an important reason I was willing to invest that early.

The transaction announced on September 8 reverses that expectation. Tamarack is issuing the stock, Headwater is accepting a one-for-one exchange ratio, and the Headwater management team is moving to a new exploration company rather than running the combined business.

I remain constructive on Tamarack’s Clearwater assets. But the deal and the stock are separate questions. Tamarack got the better end of the transaction. As a combined entity, the shares are too expensive.

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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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By: Jon Costello

Editor’s Note: WOMM (What’s on My Mind) is a new weekly publication from Jon Costello.

A land grab is underway in Venezuela’s oil industry.

After years of sanctions, political instability, deteriorating infrastructure, and a hostile investment environment kept most foreign capital away, companies are moving back in. Chevron (CVX) is planning billions of dollars of additional investment. Eni has committed to a new heavy-oil development. Other international operators are pursuing opportunities, and the United States has backed an effort to redevelop 17 Venezuelan oilfields containing enormous quantities of crude. Venezuela currently produces only around 1.2 million barrels per day, compared with more than 3 million barrels per day in the late 1990s, so the opportunity to restore lost production is substantial.

It merits a look.

But I want to be clear at the outset: I don’t particularly like investing in land grabs unless I’m properly equipped to evaluate the risks or can participate with very little capital at risk. Those risks are most acute in the earliest stages of a land grab, which is where Venezuela appears to be today.

When capital suddenly rushes into a market that was effectively closed only a short time earlier, investors are being asked to make long-term decisions before anyone really knows what normalized conditions will look like. Asset prices, contractual terms, competition, regulation, and political relationships are all being established at the same time.

That is not an environment in which I find it easy to commit capital.

Why I’m Wary

The opportunity in Venezuela is especially complicated because the risks have very little to do with whether the oil exists.

Venezuela possesses some of the largest petroleum resources in the world. The bigger questions concern everything surrounding those resources: who ultimately controls them, what fiscal and contractual terms operators will face, how much capital will be required to drill the oil, rebuild the supporting infrastructure, transport it, and get it to export markets, how durable those arrangements will prove, and what protections investors will actually possess if conditions change.

These aren’t theoretical concerns.

Reuters has reported that aspects of the rapidly emerging Venezuelan investment framework are already raising concerns among major international producers, particularly around contract stability, legal protections, transparency, and the structure of recently negotiated agreements. ExxonMobil (XOM) and ConocoPhillips (COP), whose Venezuelan assets were nationalized in 2007, are among the companies approaching the country’s reopening cautiously.

That history is difficult for me to ignore.

At HFI Research, we have considerable experience investing in Latin American oil and gas companies. For my part, I have been doing so as an outside passive equity investor since 2008. Since then, Latin American names have been among the largest holdings in the funds I manage.

That experience has taught me that the region can offer extraordinary resources and tremendous investment opportunities. It has also taught me how quickly circumstances outside management’s control can overwhelm what initially seemed like a sensible business plan.

Governments change. Fiscal regimes change. Regulations change. Contracts can change. And these changes are rarely telegraphed in advance. They can arrive suddenly and completely alter the investment’s economics.

I like investing in businesses where I can develop a reasonable idea of what management intends to accomplish and then watch that strategy unfold over several years. In parts of Latin America, the chessboard itself keeps moving. A rational strategy today can become considerably less attractive because of an election, a tax increase, a regulatory decision, or deteriorating relations with the government.

My time horizon makes those risks particularly important. When I make an investment, I generally look out at least five years, preferably longer. I am therefore less concerned with whether conditions are favorable today than with whether I can reasonably expect the conditions underpinning an investment to endure through my holding period. The longer the horizon, the more opportunities there are for governments, contracts, fiscal regimes, and political relationships to change.

Venezuela takes that problem to another level.

Why Venezuela Is Different

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By: Jon Costello

Please read: (Idea) Greenfire Resources - The Stock Is Undervalued

When I last wrote about Greenfire Resources (GFR) in July, I valued the shares at roughly C$14, or around $10 on the U.S. listing, and said I intended to subscribe for at least my pro rata share of the company’s coming rights offering once the final terms were known. Those terms are now final. I will exercise enough rights to preserve my ownership, but I do not intend to request additional shares.

That is a less bullish conclusion than I reached in July. The Connacher acquisition gives Greenfire a much larger reserve base, and the upsized rights offering leaves the company less leveraged than the original financing plan. But revisiting the numbers exposed a weakness in my earlier analysis. I did not charge Greenfire’s legacy assets enough capital to hold production flat, even as Hangingstone production continued to decline. A simplified year-end 2025 proved-reserve reference still gets me to roughly C$10.97 per share versus C$8.57 on September 3. That is enough value to keep me interested, but realizing much of it will require better execution than Greenfire has demonstrated so far.

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By: Jon Costello

See the original 2025 write-up (public): (Idea) Our #1 Metallurgical Coal Stock Pick - Warrior Met Coal

See the July write-up: (Idea) Warrior Met Coal: One Of The Best Met Coal Names

I have been bullish on Warrior Met Coal for more than a year, largely because I believed the completion of Blue Creek would transform the company’s economics. I first published a long write-up on July 2, 2025. Since then, HCC shares have performed very well.

Given the price appreciation, the thesis is now being borne out. Blue Creek has increased Warrior’s production capacity, lowered its unit costs, and helped turn the company into a much larger free cash flow generator.

Yet I am less enthusiastic about the shares today than I was when I last wrote about Warrior in July. The reason is straightforward. The business has improved, but the share price has improved even faster.

Warrior recently traded around $105 per share, after having traded in the high $70s when I published my previous update. At the time, I wrote that the shares remained attractively priced relative to my estimate of their value. Since then, metallurgical coal prices have rallied sharply, sparking investor enthusiasm for the shares.

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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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