By: Jon Costello

Please read Part 1, “(Public) The Oil Shortage: The Market Is Still Underpricing, Part I.”

In Part I, I argued that the global oil market is considerably tighter than current crude prices suggest, with the shortage so far concealed by inventory withdrawals, strategic reserve releases, reduced Chinese imports and other temporary buffers. If that shortage persists, its consequences extend well beyond the price of oil.

In this second and final part, I examine four of the most important consequences I believe could follow from a prolonged disruption: a shift in power within the global oil market, a lengthy and potentially expensive process of rebuilding depleted inventories, the possibility of an oil-shortage recession, and the implications of such a downturn for the stock market. I then consider what these risks mean for investors and how I believe they should be approached.

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By: Jon Costello

The following is an excerpt of a letter I wrote to investors in an investment partnership I manage. It is the first of two parts. The second part will address consequences to the oil and stock markets.

More than five months after the Strait of Hormuz was first closed, the global oil market is confronting a supply disruption unlike anything in modern history. Yet crude prices continue to reflect a market that appears remarkably unconcerned. I believe that complacency is misplaced. The shortage has so far been masked by massive inventory withdrawals, strategic reserve releases, sharply reduced Chinese imports and lower refinery runs—temporary buffers that are increasingly being depleted. In this first of two parts, I examine why I believe the physical oil market is considerably tighter, and the risk of substantially higher prices considerably greater, than current crude prices suggest.

The Largest Oil Supply Disruption on Record Is Underway

The closure of the Strait of Hormuz—the chokepoint through which roughly one-fifth of the world’s petroleum liquids normally passes—has produced the largest oil supply disruption ever recorded, well above the previous record of roughly 3.5 million barrels per day seen in 1974 during the Arab oil embargo.

The magnitude of the ongoing inventory draw is difficult to overstate. Saudi Aramco estimated on August 4 that the conflict had removed roughly 11 million barrels per day of liquid supply, with much of that loss temporarily absorbed through strategic reserve releases, commercial inventory withdrawals, and regional demand reductions.

More important for assessing the damage already done, Aramco estimated that rebuilding depleted inventories could require approximately 2.1 million barrels per day of surplus supply for up to 18 months. That implies a cumulative inventory loss of roughly 1.15 billion barrels. Because that depletion occurred over approximately five months, it equates to an average inventory draw of about 7.6 million barrels per day.

The scale of the disruption becomes clearer when contrasted with the largest oil supply deficits of the past half-century, presented in millions of barrels per day (mb/d).

Factoring in temporary offsets to the supply loss, the net effective supply deficit is roughly 3 to 4 million barrels per day, placing the disruption in the same range as the 1974 Arab oil embargo.

However, that comparison understates the risk. Much of today’s shortage has so far been absorbed through extraordinary withdrawals from commercial inventories and strategic reserves, along with reduced Chinese imports and other forms of demand management. Those buffers are finite. As they are depleted, even an unchanged or reduced supply deficit becomes progressively harder for the market to absorb. Unless additional production reaches the market or demand falls further, an increasing share of the adjustment will have to come through higher oil prices.

Why I Believe Oil Remains Underpriced

Oil prices remain well below the levels implied by the ongoing supply disruption. Oil futures prices reported in the financial media reflect market conditions almost exclusively in the here and now. Most contracts expire within a few months, so traders holding them are largely indifferent to market-moving events beyond that horizon. This structure explains how oil futures can trade as if the crisis were resolved while the physical market’s supply/demand balance tightens by the week.

While near-term futures prices can be a useful gauge of immediate supply and demand, oil’s “fair value” is more reliably gauged by the relationship between prices and inventories. That relationship is nonlinear, as prices tend to rise at an accelerating rate as inventories fall.

By early August, the global oil market had lost well over one billion barrels of inventory, depleting roughly 14% of the inventory that existed before the conflict. The supply deficit shows no signs of abating, while tankers and onshore oil infrastructure are now repeatedly being attacked across the Middle East. Yet WTI remains in the low-$80s—only about 20% above its prewar level. The disconnect between the physical oil market and oil prices remains remarkable.

Statistical fair-value models that I believe are reliable currently place WTI’s fair value above $100 per barrel, implying a gap between price and fair value of 30% to 40%, at the extreme of historical deviations. Moreover, as inventories continue to fall while prices remain in a narrow range, the gap widens.

Four visible factors explain why prices have been unable to mount a sustained rally.

First, governments have released large volumes of oil from strategic reserves. Those releases have been effective in offsetting supply losses. Consider that of the 62 million barrels removed from developed-country inventories in June, 44 million came from strategic reserves rather than new production. Strategic reserves are a finite resource, and their usable capacity is being rapidly depleted.

Second, computer-driven funds, which account for a large share of futures trading, reduce exposure automatically when volatility rises, regardless of the physical supply-demand balance.

Third, the market has repeatedly valued negotiations as though they had already succeeded.

The fourth factor is massive selling of crude futures by unidentified parties. Short positioning in the futures market is at historic highs even as the physical market is experiencing the most severe oil supply disruption on record. I have rarely seen such an extreme divergence in all my years participating in markets. One possible explanation is that government-affiliated funds are selling crude futures to suppress prices and limit the economic damage that would result if oil rose to levels more consistent with current supply risk and inventory-depletion trajectories. I want to emphasize, however, that this is my suspicion rather than a conclusion supported by direct evidence.

Suppressed prices have consequences. If oil prices are held below the level required to balance supply and demand, the effect can resemble a price control, since the shortage is not resolved, producer and consumer adjustments are delayed, and the eventual correction can become more severe.

During a supply crisis, high oil prices perform an essential economic function. They encourage additional production, discourage marginal consumption, and force conservation. Preventing that price signal from doing its work does not eliminate scarcity; it merely postpones the adjustment. If the current path continues, I believe outright physical shortages are increasingly likely.

A Deal Has Been Priced In Repeatedly, but Never Delivered

Oil’s underpricing has been repeatedly reinforced by U.S. jawboning since the crisis began. Over and over, threats of imminent military escalation have been followed by postponements, ceasefires, or claims of progress in negotiations, sending crude prices sharply lower and inflicting losses on traders positioned for a tighter physical market.

Since March, some version of the same jawboning sequence has occurred at least eight times:

• March 21–26: The U.S. threatened to “hit and obliterate” Iranian power plants unless Hormuz reopened within 48 hours. The strikes were postponed two days later amid claims of “very good and productive” negotiations, and the deadline was subsequently extended by another 10 days.

• April 7: The U.S. warned that “a whole civilization will die tonight.” Hours later, a two-week ceasefire was announced to provide time to conclude a proposed 10-point plan.

• April 21: The president said he expected the U.S. “to be bombing” if talks failed. Later that day, the ceasefire was extended indefinitely after mediators requested more time.

• May 17–18: The U.S. warned that “the Clock is Ticking,” then held off a major strike at the request of Qatar, Saudi Arabia, and the UAE, citing “serious negotiations.”

• June 11: The president said the U.S. would hit Iran “VERY HARD TONIGHT.” The operation was canceled hours later after another claimed negotiating breakthrough.

• June 14: The U.S. and Iran announced a 60-day framework that included a ceasefire, the lifting of the U.S. naval blockade, and the reopening of the Strait. Almost immediately thereafter, oil gave back its war premium.

• July 27: The bombing campaign was paused to give diplomacy another opportunity.

• August 1: The U.S. declared that it was “locked and loaded,” then canceled a planned attack after claiming that Iran had agreed to the parameters of a deal.

In the end, none of these threatened strikes, ceasefires or purported negotiating breakthroughs has produced a sustained increase in oil flows through the Strait of Hormuz. The details have varied, but the pattern has been remarkably consistent: a deadline is announced, military action appears imminent, negotiations are said to be advancing, and the deadline is then postponed. All the while, Iran has repeatedly disputed the suggestion that meaningful negotiations are underway. Even in July, when the two sides appeared closest to an agreement to reopen two shipping lanes, Iran’s senior negotiator publicly dismissed the prospect of a deal, saying, “Don’t even think about it.”

Iran continues to throttle oil flows through the Strait of Hormuz. At present, flows are running at less than 5 million barrels per day, down from more than 20 million barrels per day before the conflict and from a brief surge to roughly 15 million barrels per day in June. Much of that surge was attributable to Iranian tankers exiting after the U.S. temporarily eased its blockade of Iranian commerce.

More than five months after the Strait first closed, satellite tanker-tracking firm Kpler estimates traffic remains at just one-quarter of its prewar level.

Source: Rory Johnston, Kpler, X, Aug. 11, 2026.

Kpler’s estimates should not be treated as precise, and actual oil flows through Hormuz may be higher than the figures shown above. But the estimated shortfall is so large that I do not believe any plausible measurement difference could eliminate it. Even if Kpler is materially understating current flows, they would still have to be several multiples higher than its estimates to erase what remains a significant global supply deficit.

For the oil market to begin returning to anything resembling its prewar normality, flows through Hormuz will have to increase substantially from current levels.

Iran’s Demands Are Hardening

Which brings me to the present day. Iran’s negotiating position appears to be hardening, and its demands now go far beyond simply ending the conflict. Tehran is now demanding:

• The withdrawal of U.S. military forces from the region.

• A permanent end to the U.S. war against Iran.

• An end to U.S. military action against Iran’s regional allies in Lebanon, Palestine, Yemen, and Iraq.

• No further U.S. military threats against Iran.

• An end to the U.S. naval blockade of Iranian ports.

• The lifting of U.S. sanctions against Iran.

• The unconditional release of Iran’s frozen foreign assets.

• Full compensation for war damage.

Iran’s parliament is also considering barring ships from hostile countries, including the United States and Israel, from transiting Hormuz until those countries compensate Iran for war damage.

These are not the demands of a government urgently seeking a deal. They suggest Tehran believes its bargaining position is strengthening and that time is working in its favor.

My read is that Iran understands where much of that leverage comes from: oil. Hormuz does not have to remain closed indefinitely for Iran to benefit. Disruption merely has to persist long enough to tighten the market and push oil prices materially higher. The higher prices rise, the greater the economic cost imposed on Iran’s adversaries and the stronger Tehran’s negotiating position becomes.

The Strait of Hormuz Is Iran’s Real Deterrent

Iran’s greatest strategic victory may ultimately have little to do with the terms of whatever agreement ends the conflict. It may instead come from convincing the United States, Israel and the rest of the world that disrupting Hormuz represents a powerful economic deterrent. If military action against Iran credibly threatens sharply higher energy prices, oil shortages, renewed inflation and potentially a global recession, the cost of intervention rises considerably.

That possibility could force the U.S. and Israel to think much more carefully before undertaking future military action. In that sense, the ability to disrupt Hormuz could ultimately prove more valuable to Iran than a nuclear weapon, which would be extraordinarily difficult to use without inviting catastrophic retaliation.

Influence over a critical artery of the global oil market, by contrast, can be exercised in degrees, repeatedly and without crossing the nuclear threshold. Whether Iran can establish such a deterrent remains to be seen. Still, I increasingly believe that demonstrating the economic power of the Strait of Hormuz has become one of Tehran’s most important strategic objectives.

The Supply Disruption Has Spread Beyond Hormuz

The more recent problem is that the disruption is no longer confined to the Strait of Hormuz.

On July 20, the Houthis entered the conflict, opening a second front against oil flows through the Bab el-Mandeb Strait at the southern end of the Red Sea. This is particularly important for Saudi Arabia. With Hormuz impaired, the Saudis have been forced to divert more than 70% of their normal crude exports to the Red Sea port of Yanbu, from which barrels destined for Asia must travel south through Bab el-Mandeb. Saudi crude and refined-product shipments from Yanbu have averaged more than 4.5 million barrels per day since April, with roughly 70%—more than 3 million barrels per day—bound for Asia. The Red Sea route has therefore become Saudi Arabia’s principal means of maintaining exports. At the same time, Hormuz remains impaired, yet even these flows amount to only about half of the Kingdom’s pre-conflict output.

Houthi attacks and threats have now placed those barrels at risk as well. Kpler measured Saudi crude transiting Bab el-Mandeb falling from roughly 3 million barrels per day before the attacks to about 1.5 million barrels per day immediately afterward. I would therefore characterize more than 3 million barrels per day of Saudi supply as newly exposed to disruption or costly rerouting, with roughly 1.5 million barrels per day initially displaced. Those barrels are not necessarily lost. Some cargoes can be redirected north through the Suez Canal or around Africa, but doing so adds time, freight costs, and logistical constraints precisely when the global oil market has little remaining capacity to absorb another disruption.

The threat to oil supply has also spread beyond these two critical shipping lanes. On July 27, Iran-backed militias launched drones at Saudi oil facilities in the Eastern Province, including the Abqaiq area, home to the world’s largest crude-oil processing complex. Kazakhstan’s output was cut roughly in half in late July after drone attacks shut the Caspian Pipeline Consortium’s Black Sea terminal, removing approximately 900,000 barrels per day. Inside Russia, Ukrainian drones have struck nearly half of the country’s refining capacity at least once since April, while fuel rationing now affects roughly 50 million people. None of these disruptions would be resolved simply by an agreement between Washington and Tehran.

The significance for the oil market is cumulative. Each new disruption removes another layer of redundancy from the global supply system, forcing barrels onto longer routes and leaving less logistical capacity to absorb the next shock. With inventories already heavily depleted, even modest additional losses could disproportionately affect prices.

The Global Oil Supply Buffer Has All but Disappeared

Before the Iran war, global oil inventories totaled approximately 8.4 billion barrels. Still, much of that oil was working inventory required to keep pipelines, refineries, terminals and the broader distribution system operating.

Source: J.P. Morgan estimates.

Moreover, that headline inventory figure substantially overstates the cushion that was actually available when the war began. At the IEA’s current estimate of 103.3 million barrels per day of 2026 demand, 30 days of consumption amounts to approximately 3.1 billion barrels. But even that understates the amount of inventory effectively tied up in the system.

J.P. Morgan estimated before the war that only about 800 million barrels of the 8.4-billion-barrel total could be drawn without creating operational stress, implying an effective operating floor of roughly 7.6 billion barrels.

On this framework, global inventories have fallen from roughly 8.4 billion barrels before the war to approximately 7.25 billion barrels today. The table below shows estimated inventory depletion since the conflict began.

Sources: IEA, EIA, OPEC, Saudi Aramco, MUFG, J.P. Morgan, and Goldman Sachs.

That depletion puts the system below the roughly 7.6-billion-barrel level implied by J.P. Morgan’s estimate of how much inventory could be drawn before operational stress begins to emerge.

The remaining barrels are not equally available: much of the strategic reserve pool is constrained by policy and national security considerations, while commercial inventories include working stocks needed to keep refineries, pipelines and terminals operating normally. In other words, the market is no longer drawing primarily from excess inventory. It is increasingly consuming the operating cushion itself. That is why further depletion could have consequences disproportionate to the number of barrels lost, including greater regional tightness, logistical disruptions and more volatile prices.

What is clear is that if the current supply deficit persists for a few more months, the market will increasingly lose access to the inventory buffers that have so far prevented the shortage from being fully reflected in prices. Commercial stocks cannot be drawn indefinitely without approaching the minimum levels needed to keep refineries, pipelines and distribution systems operating. At the same time, the usable portion of strategic reserves will be exhausted well before the headline SPR balances reach zero.

As inventories approach those limits, futures prices can become less informative as a measure of immediate physical scarcity. Refiners and consumers ultimately need actual barrels, not paper contracts, and increasingly scarce physical supply can command premiums that are not immediately reflected in the futures market.

The result is a considerably more fragile market. The marginal barrel can no longer come from storage, leaving additional production or further demand destruction as the primary mechanisms for balancing supply and demand. If new supply cannot arrive quickly enough, prices will have to rise to levels that force that demand out of the market. The risk, therefore, is not simply that the present shortage continues, but that its effect on prices becomes increasingly nonlinear as the inventories masking it disappear.

China’s Return Could Tighten the Market Further

China has been one of the most important buffers preventing the physical oil shortage from becoming even more severe. Its crude imports averaged just 7.78 million barrels per day in June and July, compared with 11.99 million barrels per day before the conflict. In June alone, imports fell to 6.2 million barrels per day, their lowest level since November 2015.

China did not suddenly stop needing oil. It reduced imports, drew down inventories accumulated earlier, and curtailed refinery activity, effectively substituting stored barrels and lower consumption for roughly 4.2 million barrels per day of imports.

Source: Barclays Research, EIA, Kpler, July 27, 2026.

That strategy has bought time, but it cannot continue indefinitely. At a 4.2-million-barrel-per-day reduction in imports, every 100 million barrels of usable Chinese inventory offsets only about 24 days of purchases. Deferred demand is not destroyed demand. As inventories decline, China must eventually choose between deeper consumption cuts and a return to the seaborne crude market.

Signs of this process are already emerging, with Chinese crude imports recovering from their June low, as shown in the following chart.

Source: Vortexa, August 7, 2026.

This return could accelerate just as Western governments become less able to supplement supply from strategic reserves, intensifying competition for the barrels still available to the market.

If China continues restoring crude purchases toward pre-conflict levels, it could materially tighten an already depleted global oil market. Excluding China, global inventories are approximately 370 million barrels below their seasonal average, the tightest reading in five years. As China returns as a major buyer, competition for the marginal barrel will intensify.

China’s return could make the price response even more nonlinear. With commercial inventories moving closer to operating minimums and usable strategic reserves shrinking, the market has much less capacity to absorb additional demand or another supply disruption without an immediate price response. Price spikes and regional shortages therefore become more likely even if the headline global supply deficit does not worsen. The same supply deficit has a much greater effect when fewer stored barrels remain available to cushion it.

China’s return would therefore matter not because its demand is new, but because deferred demand would re-enter a market with far less inventory to cushion it.

Reduced Chinese refinery activity has also helped temporarily suppress crude demand. With Chinese runs sharply curtailed, global refinery runs are roughly 6 million barrels per day below year-ago levels in a market consuming approximately 103 million barrels per day. Yet demand for petroleum products has not fallen nearly as much. The result has been sharply higher prices for gasoline, diesel, and jet fuel while crude prices have remained comparatively subdued. These are observable physical developments, including in satellite data to which I have direct access. Oil futures prices do not yet reflect the degree of tightening visible in the physical market.

Taken together, these developments show how the market has managed the shortage so far: by drawing inventories, releasing strategic reserves, suppressing Chinese imports and reducing refinery runs. None of those responses can continue indefinitely. The more important question, then, is what happens as those buffers are depleted and the shortage begins to work its way more fully into oil prices, the economy and financial markets.

Conclusion

The key point is not that the current supply deficit must grow for oil prices to rise substantially. It is that the mechanisms that have prevented the existing shortage from being fully reflected in prices are being exhausted. Inventories have already been drawn deeply into the system’s operating cushion, strategic reserves are finite, China is beginning to return to the market, and the threat to supply has spread well beyond the Strait of Hormuz. As those buffers disappear, the same supply deficit can have a much greater effect on prices, making the adjustment increasingly nonlinear.

In Part II, I will turn to what that adjustment could mean for the economy and the stock market, and why an oil shortage of this magnitude could ultimately have consequences extending far beyond the energy markets.

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.

By: Jon Costello

See the original Transocean article from May 8, 2025. It is now public.

Transocean reported second-quarter results on August 5, and at first glance the quarter looked like a step backward. Revenue declined to $966 million from $1.081 billion in the first quarter, adjusted EBITDA margin fell to 32.2% from 40.7%, and backlog declined $396 million from the May update to $6.7 billion. The decline was offset, however, by a roughly $1.0 billion agreement with Equinor (EQNR), which remains subject to license-partner approval, that would increase backlog to approximately $7.7 billion.

Despite the weak headline showing, the shares rose anyway, from $5.14 when the results were released to $5.72 on August 12. That reaction makes more sense after looking underneath the headline numbers.

In my May article, I described the first quarter as the clearest evidence in years that Transocean’s operating leverage was emerging. Deleveraging was ahead of my expectations, and the forward contracting outlook was the strongest since I began covering the company. The second quarter weakened the operating-leverage evidence but left the balance-sheet improvement intact and strengthened the case for higher dayrates. Management also raised full-year revenue guidance to $3.90 billion to $3.975 billion.

The second quarter came down to revenue, backlog and margins. The first two are less concerning after examining what drove them. Margins remain a pivotal factor because higher utilization and dayrates still need to produce sustained earnings and free cash flow.

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Please see 2025 write-up titled: (Idea) Hess Midstream - A Potential Acquisition Target For Chevron

By: Jon Costello

Last September, I wrote that I expected Hess Midstream (HESM) to be acquired by Chevron (CVX) within six to twelve months at approximately $40 to $41 per share. Lo and behold, no transaction has occurred, but HESM reached $41.44 earlier this week.

I was right about the price but wrong about how it would get there. Looking back at my earlier valuation, I placed too much weight on a corporate event and too little on HESM’s transition from a capital-intensive construction phase into a period of substantially higher free cash flow.

The shares sold off after the company reported second-quarter earnings on August 3, as the market appeared to treat lower minimum volume commitments beginning in 2028 as evidence that Chevron’s Bakken business is deteriorating. The quarter also included throughput declines across all five systems, including 18.9% for crude oil gathering and 14.6% at crude terminals.

The operating weakness is a real concern, but the table also captures the central attraction of the investment case. Adjusted EBITDA declined only 0.7%, while Adjusted Free Cash Flow increased 19.5% as capital spending fell 56.3%. HESM’s volumes are weakening, but its transition out of a capital-intensive construction phase is allowing substantially more of its earnings to reach shareholders.

Whether that improvement in cash flow is durable depends partly on how much revenue remains protected if throughput continues to weaken. That makes the structure of HESM’s minimum volume commitments central to the valuation.

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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

Note: All dollar figures are in Canadian dollars unless otherwise specified.

Obsidian Energy has built its entire investor pitch around three words: “Per share growth.” The phrase appears on its presentation’s value-proposition slide, reserves slide, and the “why invest” slide of its July 2026 presentation. It is the metric by which management wants the company to be judged by shareholders. The metric is both sensible and testable.

Results to date bear out that Obsidian has yet to demonstrate the per-share growth. Over the past three years, production per share, funds flow per share, and book value per fully diluted share have all been flat or have declined despite a 16% reduction in the share count.

The market’s skepticism is evident in the company’s market valuation. At $14.70 per share, Obsidian trades at roughly 45% of its stated proved-plus-probable net asset value of $32.35. The relevant question, therefore, is not simply whether the shares appear inexpensive, but what must occur for that discount to narrow and how much value should be assigned to the company before operating evidence materializes.

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Please read previous CLMT write-up: (Idea) Calumet - Big Upside If The Market Prices The RIN Windfall

By: Jon Costello

I began buying Calumet (CLMT) in 2022 at approximately $14.21 and have held it as the largest position in the HFIR Energy Income Portfolio for most of the period since. In May, with the stock at $31.50, I estimated a probability-weighted value of approximately $50. The shares closed on July 28 at $41.48, up 32% since May and 144% over the past year, after running to a multi-decade high of $45.20 last week.

The appreciation alone does not make the shares overvalued, but it changes the position-sizing decision because the stock has risen much faster than the D4 RIN price, a principal driver of Montana Renewables’ earnings. The RIN peaked at $2.58 on July 7 and declined 11% over the next three weeks, while CLMT has gained 12% over the same period. The pricing divergence does not invalidate my thesis, but it indicates that the market is discounting continued strength in renewable-fuel economics. With the shares approaching my probability-weighted value and offering limited base scenario upside, the question is whether the expected return still justifies the position’s size.

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Please also read: (Idea) Greenfire Resources - One Of Our Favorite Energy Names

By: Jon Costello

Greenfire Resources (GFR) has agreed to acquire Connacher Oil and Gas for approximately C$1.28 billion in cash. I own Greenfire and have followed the company closely from its 2023 public listing through the investment by Waterous Energy Fund and to the recapitalization completed last December. My investment thesis has been that the shares traded at a substantial discount to the value of Greenfire’s long-lived oil sands reserves, provided management could stabilize production and fund the next phase of development.

This proposed Connacher acquisition reinforces that thesis, but it also increases the amount of execution required to realize it. Connacher’s Great Divide oil sands project is a logical asset for Greenfire to own, and the combination of the companies’ assets creates a larger platform with meaningful operating and development synergies.

Source: Greenfire Resources Connacher Oil & Gas presentation, July 2026.

However, the purchase price already gives Connacher credit for a favorable commodity price environment and for successful post-acquisition execution by Greenfire’s management. Given the announced price, I do not consider the acquisition itself to be cheap, but I continue to believe Greenfire shares are undervalued from a long-term perspective after giving effect to the transaction and associated financing.

Connacher’s Trip From Insolvency to a C$1.28 Billion Sale

Connacher entered creditor protection in 2016. In early 2019, a C$113.5 million sale failed, and the company’s first-lien lenders acquired it through a credit bid that September. The former equity was canceled, and Connacher has remained private ever since.

The lenders who acquired the company through that credit bid are now selling the business for approximately C$1.28 billion. Greenfire has not identified this group, so I will not speculate about the returns generated from this deal. The relevant point is that Greenfire is not buying from a distressed owner. The transaction marks a full exit for creditors who controlled the asset for nearly seven years, which argues for a conservative evaluation of the acquisition price.

Connacher Is an Unusually Strong Strategic Fit

Connacher’s Great Divide in-situ oil sands project sits directly adjacent to Greenfire’s Hangingstone operation. Both assets are produced from the McMurray formation and use the same regional pipelines. In this deal, Greenfire will combine two neighboring SAGD assets, rather than entering a new basin or operating model, thereby roughly doubling the company’s scale.

Great Divide’s Pod One and Algar processing facilities currently support approximately 20,000 barrels per day and are reported to have brownfield expansion potential toward 30,000 barrels per day, as shown below.

Pod One is the stronger of the two facilities, with a steam-oil ratio of 2.6x compared with 3.5x at Algar.

Greenfire’s management team also has an unusually high degree of familiarity with the asset, having spent more than fifteen years in prior roles at Connacher. That history reduces integration risk, although it does not eliminate operating risk.

Management has identified approximately C$30 million in annual savings from midstream, marketing, and operating costs, and G&A, while the combined company will have roughly C$2.8 billion in tax pools that should enable it to defer cash taxes until after 2030. These benefits strengthen the strategic rationale for the transaction, though they do not by themselves establish that Greenfire is acquiring Connacher below intrinsic value.

The Reserve Valuation Is Attractive

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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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Occidental 2024 write-up (public)

Occidental 2025 write-up (public)

By: Jon Costello

The market continues to value Occidental Petroleum (OXY) as a heavily indebted company. That description is becoming obsolete faster than investors appear to recognize.

When I last revisited OXY in June 2025, I expected balance-sheet repair to remain the dominant issue through 2027, with larger repurchases and dividend increases beginning in 2028. I was too conservative. OXY ended the first quarter of 2026 with $13.3 billion of long-term debt, down from a post-CrownRock peak of $28.9 billion and only $3.3 billion above management’s near-term target of $10 billion. At sustained oil prices above the mid-$70s per barrel, the company should reach that target within months.

That timing matters because the oil market is pricing an orderly reopening of the Strait of Hormuz and a quick disappearance of the recent risk premium. That assumption strikes us as too complacent. OXY is one of the cheapest large-cap ways to express the opposite view, but the investment thesis no longer depends only on higher oil prices. It also rests on a balance sheet that has already improved substantially.

The Balance Sheet Changed Faster Than I Expected

The OxyChem sale closed on January 2, and management applied the proceeds to debt. Since December alone, OXY has reduced long-term debt by $7.5 billion. Total debt has fallen to $15.7 billion at the end of the first quarter from $25.6 billion a year ago.

The improvement extends beyond the headline debt reduction. OXY’s annual interest run-rate is approximately $845 million, roughly $550 million below the 2025 level. Near-term maturities are also modest, with only $415 million due through the end of 2029. The company no longer needs favorable capital markets to complete the remaining deleveraging.

The following chart shows OXY’s total debt at carrying value over the past five quarters.

OXY’s long-term debt position now supports, rather than constrains, the investment case for owning OXY shares.

At the oil prices used in my valuation, OXY should reach $10 billion of long-term debt in approximately three to five months. The relevant question is therefore no longer whether the balance sheet will be repaired, but how management will allocate cash once that target is reached.

Why the Discount Has Not Disappeared

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By: Jon Costello

Please be sure to read:

(Public) Our #1 Metallurgical Coal Stock Pick - Warrior Met Coal

A year ago, I bought shares of Warrior Met Coal because I believed its Blue Creek project would transform an already low-cost producer into a much larger free cash flow generator.

The company has now completed the roughly $1 billion project ahead of schedule, within budget, and without adding funded debt, while the first quarter provided the clearest evidence yet that Blue Creek is lowering Warrior’s companywide cost structure.

Since then, the shares surged to $110 and have since pulled back into the high-$70s as elevated freight costs and weak price realizations have obscured the improvement in the underlying business.

In this article, I review what has changed since my original investment thesis, estimate Warrior’s value across several coal price scenarios, and explain why I believe the shares have become attractive again.

Rising Coal Prices Failed to Sustain a Higher Stock Price

Metallurgical coal has gone from glutted to tight in six months. The premium low-vol benchmark out of Australia fell below $200 per metric ton in the second half of 2024, spent most of 2025 between $170 and $200, and now trades in the mid-$230s.

Two supply-related disruptions drove the move.

The first came from China. After a May 22 gas explosion at the Liushenyu mine in Shanxi province killed at least 82 people, regulators halted 109 mines representing roughly 122 million tons of annual capacity. Chinese coking-coal production fell by an estimated 288,000 tons per day. By June 5, suspensions had eased to 59 mines, but the initial loss of supply tightened the broader coking-coal complex and lifted the seaborne premium low-vol benchmark that influences Warrior’s Mine No. 7 pricing.

The second disruption came from transportation. Since late February, the Iran war has sharply reduced traffic through the Strait of Hormuz, pushing dry-bulk freight costs higher. This matters because Warrior pays freight on High Vol A coal sold into the Pacific Basin on a cost-and-freight basis. Higher benchmark prices have therefore been partly offset by freight costs, compressing margins and contributing to the stock’s weakness.

Where the Thesis Stands

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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”.

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There is no shortage of refiner bulls right now, and I am sympathetic to them because I’ve been in that camp myself. In April 2024, I recommended buying Valero (VLO) “for the long term.” The stock has climbed from roughly $162 to around $266, a gain of about 64%.

The bullishness is justified from a macro perspective. Fundamentals for the industry are stronger than ever. Refining margins are at historic highs, U.S. gasoline inventories sit about 5% below the five-year average and distillate about 10% below, refineries are running flat out near 96% utilization, and my own forecast keeps refining margins supported for the next couple of years as global runs recover from this spring’s disruption and clean-product stocks take until the back half of the decade to rebuild.

So I’m not bearish on refining margins or, in a broader sense, today’s refiner sector fundamentals. Rather, I believe there are factors at play that are more consequential for long-term holders at current stock prices.

Today’s Macro Bull Case for Refiners Is Strong

The strongest version of the bullish refiners thesis states that refining capacity has been rationalized across the West, the survivors are complex and well run, and product inventories are genuinely tight. Margins have remained elevated since 2022 and stand at their highest point relative to Brent prices in history, as shown in the following chart.

In point of fact, if margins remain at today’s levels, Valero will generate enormous cash flow, and so will Marathon Petroleum (MPC) and Phillips 66 (PSX). The problem is, first, I believe today’s high refining margins are likely to revert to lower levels, and second, refining economics at lower margins translate into lousy long-term investment returns.

Refiners Don’t Control the Variable That Matters Most

Refining is a spread business. A refiner buys crude at a price fully out of its control, sells a product at a price also out of its control, and keeps the difference, which is known as the “crack spread.” That spread forms the basis of a refiner’s fundamental performance.

The problem for the industry’s equity investors is that performance is determined by forces that are impossible to forecast, making valuation a complicated undertaking.

To properly value a refiner, an investor has to discount the crack spread to a realistic price and arrive at a stock price suitable for holding through the industry’s cycle. It helps to have a view on the direction of margins, but I’ve found this exercise to offer little value outside of one or two quarters into the future—and even that is extremely difficult.

Complicating the picture further is the marginal barrel of refined product supply. China has built itself into the world’s largest refiner, adding 5.5 million barrels per day of capacity between 2011 and 2023. It now runs a structural surplus managed through government export quotas.

When Beijing increases those quotas, its refined products flood the seaborne market, driving global crack spreads lower. When it tightens them, the dynamic is reversed.

In other words, a U.S. refiner’s margin swings on policy decisions made in Beijing under the country’s five-year plan, as well as potentially in an ad hoc manner in response to market conditions. Layer on a global capacity wave still under construction and a Chinese gasoline market possibly approaching its peak as electric vehicles take market share, and the single most important variable in the business is one its investors and managers cannot influence at all.

Operating Leverage is Extraordinary, But Cuts Both Ways

Another complicating factor in valuing refiners and owning refining stocks is the operating leverage these businesses face. This is no secret, as the refiners disclose it themselves.

Marathon’s investor presentation states that a one-dollar move in the blended crack spread changes its annual refining EBITDA (its operating earnings) by roughly $1.1 billion; Phillips 66 puts a one-dollar move in its refining indicators at about $700 million; and Valero’s throughput of nearly 3 million barrels per day implies the same order of magnitude.

The 3-2-1 crack—the standard benchmark for the margin on turning three barrels of crude into two of gasoline and one of distillate—has ranged from the low teens to well above $40 a barrel in just the past few years.

And the volatility in crack spreads can cause cash flow to swing wildly. A $10 move in the crack, comfortably inside that range, swings annual earnings by roughly $11 billion at Marathon, $11 billion at Valero, and $7 billion at Phillips 66. This all-important variable is therefore not a reliable input for valuation. It’s ultimately more of a guess about a quota number set in Beijing and the world’s oil chokepoints, and the companies are telling you so in their own presentations. A proper valuation has become too difficult for me to render on a reliable basis, and, frankly, I’m wary of anyone who claims they can do so.

Put that torque in per-share terms, and the value trap to which current refining investors are exposed comes into focus. At the 2022 peak—the best year these businesses ever posted —Valero threw off about $34 of free cash flow per share, Marathon roughly $46, and Phillips 66 about $21. Capitalize that peak at nine times, the peak multiple the market has paid for refiners for years, and the math puts Valero’s stock at $310, Marathon’s at $413, and Phillips 66’s at $192. That represents upside of 17%, 58%, and 11%, respectively, from today’s prices. And that is the reward for everything breaking right at once, including a peak crack spread, peak cash flow, and a peak multiple.

Now invert it. Using average free cash flow from 2023 to 2025 valued at a more sober seven times, Valero is worth about $128, Marathon $167, and Phillips 66 $56. That is 36% to 68% below where the three trade today.

The bear case, which assumes trough cash flow on the same multiple, gets worse still. Today’s price already covers the best year on record, and the base case sits one-third to two-thirds lower. Exhibit 2 sets the three scenarios side by side.

The asymmetry between these three scenarios is the whole case. At their current prices, these stocks offer limited upside and significant downside. Moreover, that downside may be prolonged unless refining margins remain elevated at historic highs.

Beware of “Cheap” Refiner Stocks

There is a second trap inside the cheap-looking refining names. The refiners that screen cheapest are usually the inland and heavy-crude players whose competitive advantage, when they were built decades ago, was a wide discount on Canadian and other heavy-crude barrels. This discount represents the difference at which heavy Canadian crude trades below the U.S. WTI benchmark, which those refiners pocket as extra margin.

That edge has narrowed structurally. Since the Trans Mountain expansion (a new pipeline that gave Canadian crude another route to market) opened in 2024, the Western Canadian Select discount has narrowed by roughly $3 per barrel, now averaging around $13, compared with historical levels north of $20. Cheap, in refining, usually means most exposed.

HF Sinclair (DINO) and Delek US Holdings (DK) are the poster children.

For HF Sinclair, each of its seven refineries has the complexity to convert discounted, heavy or sour crudes into high-value products. Three of these refineries are fed by pipelines carrying Canadian barrels, namely, its El Dorado, Parco, and Puget Sound refineries, the last of which is supplied directly from the Trans Mountain system. This fall, the company is completing a project at El Dorado that allows up to 10,000 more barrels per day of heavy crude to be added to the mix. That is new capital tied to a discount that has already narrowed.

Delek learned the same lesson a cycle earlier. It can deliver roughly 200,000 of its 302,000 barrels per day of crude straight from West Texas, and its Big Spring refinery is the closest plant in the country to Midland. When Permian production outran the pipelines in 2018, local barrels sold for as much as $18 per barrel below the U.S. benchmark, and refiners buying at Midland prices pocketed the difference. However, new pipelines to the Gulf Coast cut that discount. It went as low as $1 per barrel by late 2019, and the windfall refiners were able to capture went with it.

Cheap-looking refiners are cheap because the discounts that made them money keep shrinking. The market isn’t missing the value. It is pricing in the reduced value.

“Rationalization Made Them Quality” Misreads the Market’s Verdict

The strongest pushback against these bearish factors complicating refiner valuation is that consolidation has changed the business and that the survivors are durable, quality earners now, not the boom-and-bust refiners of the past. I will concede the first half. Margins may well stay elevated for the next few years.

But the risk for equity investors is that elevated margins represent the top of a cycle, not a permanent plateau. In fact, a supply response that ends every refining up-cycle is already building, as runs recover, the capacity wave lands, and products rebuild in the late 2020s.

More to the point, the market has already run the cyclical valuation experiment. Refiners earned a fortune from 2021 to 2025. However, they were never awarded a quality multiple for it.

In my 2024 work on Valero, its shares traded within a 5x-to-9x free-cash-flow band for years, around their long-run average, even as their returns on capital improved. The group as a whole has never been re-rated as a compounder, meaning the market has never agreed to pay a higher multiple for the same dollar of refining cash flow. The reason is visible in the returns themselves.

Start with the earnings, as shown in the following chart.

Valero’s net income ranged from under $1 billion in 2021 to $11.5 billion in 2022 and back to $2.3 billion in 2025. Return on equity, profit measured as a share of shareholder capital, told the same story.

A return on equity that swings from 5% to 49% and back is not a signal of a quality business. It is the signature of a price-taker. And the way the cash is distributed to shareholders compounds the issue for an income investor. These companies return capital overwhelmingly through repurchases. Valero spent $2.6 billion on repurchases versus $1.4 billion on dividends in 2025, and the group’s dividend yields now run from under 2% to about 3%, with Valero and Marathon both below 2%. That is a total-return trading vehicle, not an income holding.

None of this means you cannot make money trading refiners. In theory, you can buy them cheap based on through-cycle earnings and sell them at higher prices later in the cycle. But trading a cyclical stock and owning a business for long-term appreciation and/or income generation require different approaches, and my process here embraces the latter.

Own the Toll Road, Not the Refinery

If you believe in refined-products recovery, I believe there are better ways to play it than by owning the refiners directly. Instead, you can own the refined product toll road. Midstream operators that gather, process, and move crude and products earn fee-based, contracted cash flows that do not depend on the crack spread. The volumes move whether the refiner’s margin is fat or thin.

My preferred vehicle is MPLX, LP (MPLX), the logistics partnership built around Marathon. It is, in effect, the toll road bolted to a refiner, and it is the better business.

MPLX is particularly attractive for income investors. It yields roughly 7.6%, more than double the refiners’, on a distribution covered comfortably, it earns well more than it pays out, and its distribution is growing at a 12.5% annual clip, backed by volume commitments running into the 2030s. MPLX is not without risk. It relies on Marathon as both a sponsor and its largest customer, and it comes with the K-1 tax form that some investors would rather avoid. But its cash flow is contracted, and its payout is covered through a cycle, which is precisely what the refiners cannot say. I have owned and recommended it for years, and the contrast in its business quality with refiner customers is the crux of this article.

Integrated Refiners Hedge the Spread

There is another way to maintain exposure to refining, albeit indirectly. Own it inside an integrated oil company, where the refinery spread that can’t be reliably valued is hedged by the barrels the company pumps itself.

Cenovus Energy (CVE) and Suncor Energy (SU), each a holding in the HFIR Energy Income Portfolio, combine oil-sands production with refining and marketing, so the two halves of the cycle offset one another. When crude is cheap, refining margins widen. When crude prices rise, the upstream segment earns it back. Refining stops being the whole investment and becomes a balancing weight, the one thing a pure refiner can never be. Both are long-life, low-decline producers with oil-sands reserves measured in decades rather than the five to eight years of a typical shale driller, and both now return cash through growing dividends and repurchases.

I have recommended both for years. I called Suncor a buy for its yield and its torque to higher oil after management’s capital-allocation turnaround took hold, and I have backed Cenovus repeatedly on weakness as the oil-sands laggard whose results kept beating the tape. Neither is a pure crack-spread bet. You keep refining in the mix and still own cash flows you can actually model.

Calumet as a Special Situation

One name breaks every rule in this piece, and it is a core holding in the HFIR Energy Income portfolio. Calumet (CLMT) has a refining segment, but it is not a commodity refiner. Its value sits in Montana Renewables, a low-cost producer of renewable diesel and sustainable aviation fuel. The rest is specialty products — lubricants, solvents, and waxes — sold into niche markets where Calumet holds real pricing power. Its returns hinge on renewable-fuel economics, a federal loan guarantee, and clean-fuel policy, not on the spot 3-2-1 crack.

All these are higher-quality business factors than those of refiners. A contracted, idiosyncratic, low-cost business is a different animal from a spread set in Beijing. I have owned and recommended Calumet since 2022, and I considered it one of the largest upside opportunities in my coverage universe, with returns largely uncorrelated with oil prices or the broader market. Importantly, what drives its stock price is completely unrelated to refining economics.

Conclusion

I am avoiding the U.S. independent refiners—Valero, Marathon, Phillips 66, and the smaller names alongside them—and that means reversing the Valero buy call I made in April 2024. The margin thesis was right, and the stock rose about 64%, and I would make that trade again. But this stock is not worthy as a core long-term holding.

I will change my mind under specific conditions: a durable re-rating of the group to roughly 10x free cash flow, through-cycle returns on equity that hold above the cost of capital rather than collapsing in every downturn, or refiners signing long-dated contracts that finally decouple their earnings from the spot crack. None of that is true today.

Until it is, I would rather own refinery-related stocks than the refiners themselves. An income investor holding pure refiners into this strength has better options, such as MPLX at more than double the yield on contracted cash flow, an integrated like Cenovus or Suncor that hedges the spread, or Calumet that sidesteps the negatives entirely, and every one owns assets and generates cash flows that lend themselves to business valuation.

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

By: Jon Costello

I am taking Borr Drilling off my ‘avoid’ list.

When I last covered the stock on May 22, I set a high bar to turn constructive. I wrote that two things had to happen together: the company had to refinance its 2028 and 2030 notes on attractive terms, and the shares had to fall below $4.00. I stated that “either condition in isolation wouldn’t be enough.” One of those conditions has now been decisively resolved. The other is almost there.

The Refinancing Removes a Key Risk

Boor’s maturity wall is now gone. On May 27, the company priced and upsized a $2.035 billion senior secured notes offering, comprising $1,100 million at 8.750% due 2032 and $935 million at 9.000% due 2034. The proceeds refinance in full the $1,128 million of 10.000% notes due 2028 and the $771 million of 10.375% notes due 2030. By June 9, holders of 95.92% of the 2028 notes and 90.56% of the 2030 notes had tendered, the restrictive covenants were stripped, and the liens were released. The offering closed on June 10. This was the variable I called the most actionable catalyst for the stock, and Borr just executed it.

The new terms are better than the terms in the former notes. The blended coupon fell from roughly 10.2% to about 8.9%, and the nearest major maturity moved from May 2028 out to 2032. The refinancing did not deleverage the company; gross debt is modestly higher after fees and call premiums. But it removed the single most binary risk in my prior thesis, namely, the need to roll $1.9 billion through an uncertain 2028 capital market. That overhang is no longer the binding constraint on owning the shares.

Same Data, Better Price

My objection in May was primarily aimed at Borr’s stock price, not its business. I wrote then that the balance-sheet repair “was real and earned the rally,” and that the shares had “significant torque to higher dayrates.” My problem was that at $5.59, Borr was “already priced for” an operating recovery that had not arrived. That objection has largely dissolved. The stock has fallen by 26%, to about $4.13, while the operating data sits unchanged.

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By: Jon Costello

The oil bulls have capitulated.

For the past two weeks, crude oil has relentlessly sold off. The war premium has evaporated. WTI has fallen back to around $70 per barrel, Brent has retreated into the low $70s, and sentiment has shifted from fear of a supply shock to anticipation of another period of oversupply.

Prices are now approaching the levels seen before the war began on February 28.

Judging by price action alone, the market appears convinced that the disruption in the Strait of Hormuz is effectively over.

But that conclusion is contradicted by the evidence. Commercial inventories continue to tighten. Refining margins remain at historically high levels. Iran has demonstrated that it retains the ability—and the willingness—to interfere with shipping in the Arabian Gulf. At the same time, approaches for deriving a fair range of oil prices from inventory levels suggest prices materially above today’s market. Those observations stand in direct contradiction to oil prices, now trading at pre-war levels.

When prices and fundamentals appear to contradict one another to such a stark degree, I find it useful to separate what the market is pricing today from what the underlying economics suggest over the investment horizon that actually matters to me. Today, those two perspectives have diverged sharply. Understanding this divergence is, in my view, the key to understanding both the recent collapse in oil prices and why I remain constructive over the medium term.

As a long-term equity investor with specialization in the energy sector, I’m not trying to predict where oil will settle next Tuesday or even next month. My investment theses depend on where industry fundamentals are likely to stand over the coming quarters and years, because those fundamentals ultimately determine the intrinsic value of the businesses I own and, by extension, the returns on my investments. Short-term price movements matter, but primarily because they are caused by developments that have less bearing on the long-term outlook, not because they necessarily change an investment’s economics.

When viewed from this broader perspective, I think much of today’s acute bearishness misses an important point: that the bulls and the bears are not necessarily disagreeing about supply and demand. Rather, they’re disagreeing about the element of time.

The Oil Market Doesn’t Have One Pricing Model

One of the biggest mistakes I see investors in the energy sector make is assuming that crude oil is governed by a single equilibrium model. It isn’t.

Oil is better understood as a series of nested economic models, each with its own influence across different time horizons. The table below illustrates some of the most prominent models of this kind.

Over days and weeks, prices are driven largely by financial positioning, geopolitical developments, and changing expectations.

Over the following months, inventories become the dominant variable. Small imbalances between production and consumption can lead to surprisingly large price swings because inventories act as the market’s buffer between supply and demand.

Over one to two years, the focus shifts toward the underlying balance between global production and consumption. OPEC+ policy, non-OPEC supply growth, and demand trends begin to dominate.

Beyond that, prices increasingly reflect the industry’s marginal cost of supplying the next barrel. If prices remain above that cost, investment accelerates and supply grows. If they remain below the marginal cost of supply, investment slows, production eventually tightens, and prices recover.

Finally, over the longest horizons, today’s capital spending decisions determine tomorrow’s productive capacity. Years of underinvestment cannot be corrected overnight, while excessive investment eventually creates its own oversupply.

Each of these models is valid.

The mistake is applying a particular model to the wrong time horizon. This is exactly what I believe the market is doing today.

The Futures Market Isn’t Pricing the Medium Term

If the medium-term outlook remains constructive, why isn’t today’s oil price already reflecting it?

The answer lies in understanding what oil futures actually represent.

It is tempting to think of the front-month futures contract as the market’s forecast of where oil prices are headed over the coming year. In reality, it is nothing of the sort.

A futures contract that expires in one or two months is fundamentally a pricing mechanism for crude that will be delivered over that time horizon. As time marches on, every futures contract eventually becomes the spot market. And as expiration approaches, the distinction between futures and spot disappears. That is why the nearby contract must ultimately price today’s physical equilibrium rather than where traders believe oil might trade months from now.

Moreover, the shape of the futures curve best balances today’s physical market across all delivery months. It emerges from current supply-and-demand conditions rather than from a collection of forecasts about future spot prices.

Viewed through that lens, the recent decline in front-month crude prices becomes much easier to understand. If temporary developments are expected to increase crude availability over the next several weeks—as I believe deferred cargoes and China’s reduced crude buying have done—then weaker nearby prices are entirely consistent with how the futures market is designed to function.

That tells us something important about current conditions.

The Short-Term Bears Are Right

Once the appropriate time horizon is identified, today’s market becomes much easier to understand. The short-term price weakness is not totally irrational. In fact, given recent developments in physical crude flows, it is largely understandable.

Many oil bulls have focused almost exclusively on the supply disruptions created by Iran’s interference with shipping in the Strait of Hormuz. Those disruptions are real, and they’re having a profound impact on fundamentals. Reliable estimates put the volumes of crude oil they have removed from global supply at more than one billion barrels over the past four months.

But they are only one side of the equation. At roughly the same time that Middle Eastern exports were being constrained, two powerful countervailing forces emerged, temporarily easing pressure on the physical market.

The first was the release of the crude cargoes from the Arabian Gulf.

When shipping through the Strait became uncertain, a substantial volume of crude accumulated aboard tankers waiting for a safer opportunity to exit the Strait. As transit gradually resumed following the U.S.-Iran memorandum of understanding and the subsequent easing of sanctions on Iranian oil exports, those deferred cargoes began moving to market. Meanwhile, the U.S. lifted sanctions on the sale of Iranian oil, allowing it to be sold globally. Combined, these measures released an estimated 170 million barrels from the Gulf.

Most trapped barrels have now exited the Gulf, as shown below.

Source: Barclays

This supply did not represent new production or a sustainable increase in global supply. Rather, it was the release of barrels that had been temporarily trapped by logistical disruptions. Even so, their arrival increased prompt physical availability just as refiners and traders were reassessing geopolitical risk.

This is a one-time adjustment rather than a lasting source of supply. Once the backlog has been cleared, the surge in supply represented by those barrels cannot occur again.

The second—and arguably more important—near-term factor depressing prices has come from China.

Rather than aggressively competing for replacement crude supplies, Chinese refiners have responded to the disruption by reducing refinery throughput, drawing down commercial inventories, and operating within Beijing’s existing restrictions on refined-product exports. The result has been a sharp decline in crude imports relative to first-quarter levels.

Importantly, that decline does not represent a collapse in end-user demand for petroleum products, at least not in full. Instead, it primarily reflects a temporary combination of lower refinery runs, inventory drawdowns, and policy decisions that have reduced China’s need to purchase crude on the international market. precisely when Middle Eastern supplies have become more difficult to move.

Together, these two developments have temporarily increased prompt crude availability while simultaneously reducing one of the world’s largest sources of incremental buying. It should therefore come as little surprise that Brent time spreads have weakened to year-to-date lows, and that nearby crude prices have come under pressure. In effect, one temporary force increased available supply while another temporarily reduced demand for internationally traded crude.

Source: Barchart.com, June 26, 2026.

In other words, the market is not behaving irrationally; it is correctly recognizing that near-term physical conditions have become less tight than many expected only a few weeks ago.

Where I differ from the market is not in that assessment. It is in what happens next.

Neither the release of deferred cargoes nor China’s policy-driven demand restraint represents a permanent improvement in the global supply balance. One is a finite logistical adjustment. The other reflects commercial and policy decisions that can reverse as inventories normalize and refinery utilization recovers.

These temporary factors help explain today’s prices. They do not explain the medium-term physical balance.

The Medium-Term Outlook Remains Constructive

If the short-term bears are right, the next question becomes obvious: why haven’t prices responded the way inventories imply they would?

Historically, inventories have been among the most reliable indicators of medium-term oil prices because they reflect the cumulative effect of countless individual supply and demand decisions. Production, refinery activity, imports, exports, logistics, and demand all eventually affect inventory levels. For that reason, inventories often provide one of the clearest summaries of the medium-term physical balance.

While prices may overreact to geopolitical headlines, financial positioning, or temporary logistical disruptions, inventories ultimately reveal whether the physical market is tightening or loosening.

By that measure, today’s oil market appears considerably tighter than current prices suggest.

One approach I use to estimate fair value is a regression that relates oil prices to commercial inventory levels. Like any model, it is imperfect, and it should never be relied upon in isolation. But over long periods, it has proven useful because inventories sit at the center of the medium-term pricing model. They absorb the cumulative effects of production, consumption, imports, exports, refinery activity, and logistics.

Today, my regression indicates a fair value for WTI of approximately $87 per barrel, 26% above the current market price.

Moreover, inventories are trending lower. If continued, it will exert further upward pressure on prices.

This model is not the only evidence illustrating that the market is tighter than current prices imply.

Several independent inventory-based approaches reach broadly similar conclusions. Whether the analysis focuses on OECD inventories, global days of forward demand, or deviations from long-term inventory norms, the message is largely the same: the physical market remains considerably tighter than today’s outright price would suggest.

The implication is that prices have significantly more upside than downside. Barring a rapid normalization of flows through the Strait to pre-war levels, prices are likely to remain above $80 per barrel, and well above that, as the market tightens further.

This conclusion is also consistent with what we observe outside of inventory statistics. Refining margins remain at historic highs, indicating that refiners continue to compete aggressively for crude despite weakness in outright futures prices. Physical crude differentials remain firm across many regions, indicating that nearby barrels continue to command a premium despite weakness in outright futures prices.

None of this proves that prices must immediately move higher. As any long-term energy investor knows, markets can remain disconnected from medium-term fundamentals for longer than expected, particularly when temporary logistical adjustments dominate near-term trading.

But it does suggest that today’s weakness should not automatically be interpreted as evidence that the underlying supply deficit has disappeared.

The Strait Still Matters

In my view, the answer depends less on today’s supply levels than on tomorrow’s deliverability.

That distinction matters because oil markets are ultimately constrained not by how much crude exists underground, but by how much can be delivered to refiners when and where it is needed.

This is where I believe many analyses become overly optimistic about the medium term. Many investors view the Iran conflict as a done deal. Almost every morning, I hear CNBC commentators state this view and use it as a reason to argue for lower interest rates or for clear sailing for the economy and the stock market.

In my view, the market is making a subtle but important mistake. It is treating the recent release of deferred cargoes and China’s temporary restraint in demand as though they have permanently resolved the underlying supply deficit.

I believe they have merely postponed its effects.

Investors extrapolate the current price into the future. However, the assumption that today’s price will hold implies that barrels will continue to move to market without meaningful disruption. Recent events suggest that the assumption warrants considerably more caution than the market currently assigns it.

Iran has demonstrated its ability to interfere with one of the world’s most important energy chokepoints.

On Thursday, Iran reinforced its capability when Iranian forces reportedly attacked another commercial cargo vessel transiting the region. Then today, after a U.S. response that attracted Iranian military sites, Iranian drones were reported to have attacked Bahrain and another ship.

While two or three incidents do not determine the market’s long-term direction, they serve as a reminder that the threat to Gulf shipping remains active, not merely theoretical. Moreover, they suggest that consensus is moving too quickly to treat the conflict as resolved for oil pricing purposes.

Even if tensions continue to ease, the events of the past several months have highlighted how quickly logistical disruptions can tighten the physical market. Not because production disappears, but because deliverability changes.

Consider that a barrel of oil has little economic value if it cannot reach the refinery that needs it. Recent events in the Strait of Hormuz serve as a reminder that production and deliverability are not interchangeable concepts. The market may temporarily appear better supplied as deferred cargoes finally reach their destinations, but those logistical adjustments do not eliminate the underlying vulnerability of one of the world’s most important energy corridors.

Deliverability will remain a key issue in the oil market as long as Iran exercises control over transit through the Strait. At the moment, it is attempting to limit transit on the Strait’s southern lane, which is controlled by Oman, in coordination with the U.S military. For the moment, given the current lack of traffic through this lane according to satellite trackers we follow, it is doing so successfully.

Market participants are behaving as though the Strait of Hormuz has returned to being a solved logistical problem. Recent events suggest it has not. That distinction matters because if deliverability remains uncertain, today’s apparent easing in physical conditions may prove considerably more temporary than current prices imply

Deliverability Has Become the Critical Constraint

Other temporary supply cushions are also beginning to disappear. At current release rates, Strategic Petroleum Reserve (SPR) drawdowns have only another three to six weeks of supply remaining. Likewise, commercial inventory drawdowns outside of the SPR cannot continue indefinitely without eventually requiring replenishment. These measures can delay the market’s adjustment, but they cannot eliminate it. The common thread is that each of these developments buys time. None creates new long-term supply.

Oil is unusual among major commodities because new supply cannot be created quickly. Developing large conventional fields takes years. Expanding offshore production often takes even longer.

Even the U.S. shale industry—by far the world’s most responsive source of significant incremental supply—has become more disciplined than it was during the previous decade. Producers now prioritize shareholder returns over rapid production growth, limiting the industry’s ability to offset global supply shortfalls through sheer drilling activity.

This reality means the market’s longer-term balance depends less on today’s production than on tomorrow’s production capacity, which is why deliverability is especially important.

The implications extend beyond the immediate disruption itself.

For decades, the oil market has viewed OPEC’s spare production capacity as an important buffer against unexpected supply shocks. This view assumes that those additional barrels could be delivered to market in short order, as needed, on a scale sufficient to satisfy demand and keep prices stable. In fact, the technical definition of “spare capacity” is the ability of a producer to rapidly surge supply significantly above its current level and maintain that elevated level for at least 90 days.

Iran has demonstrated that it possesses sufficient influence over traffic through the Strait that the market can no longer assume OPEC’s spare capacity is fully available precisely when it is most needed.

If Iran can meaningfully disrupt tanker traffic through the Strait of Hormuz, then a significant portion of OPEC’s spare capacity may be less immediately available than headline production figures suggest. In other words, spare capacity and deliverable capacity are no longer synonymous. Spare capacity is only valuable if it is deliverable.

This, I believe, helps explain an important difference in perspective between oil specialists and the broader investment community. This distinction is more familiar to participants who focus on the physical oil market than to investors who primarily encounter oil through futures prices or macroeconomic commentary. Energy market participants tend to think in terms of physical flows and deliverability. Much of the broader investment community understandably focuses on reported production capacity. Under normal conditions, those concepts are nearly identical.

Other important implications flow from the emerging order oil market order. For example, spare capacity becomes far less relevant if it can’t be delivered to market in a timely manner. By rendering OPEC’s spare capacity less relevant to the market, Iran can weaken Saudi Arabia’s position as the most powerful force in the oil market, given Saudi Arabia’s control over export volumes and flows.

Conclusion

The recent selloff in oil is real. In my view, however, it reflects a series of temporary adjustments rather than a lasting improvement in the oil market’s underlying balance. Deferred Gulf cargoes have returned to market, China’s crude imports have declined, and strategic and commercial inventories have provided a temporary cushion to supply. Those developments explain why prompt crude prices have weakened. They do not, in my view, explain the medium-term outlook.

The broader evidence continues to point in a different direction. Inventories remain historically tight, and refining margins and physical differentials continue to indicate robust competition for crude. Recent events in the Strait of Hormuz have highlighted the growing importance of deliverability alongside production. Temporary adjustments have eased near-term conditions, but they have not created new productive capacity or eliminated the underlying supply deficit.

Could I be early? Absolutely. Markets often remain focused on temporary developments longer than fundamentals alone might suggest, and a sustained return to normal shipping conditions through the Strait would reduce many of the risks discussed here. But that uncertainty has not altered my outlook. I continue to believe the medium-term fundamentals remain considerably stronger than today’s market price implies, and I expect significantly higher average oil prices through the balance of the year, and likely well beyond that.

For investors with time horizons measured in quarters rather than weeks, I believe the appropriate response is to stay the course and allow the underlying fundamentals sufficient time to make their weight felt in prices.

Ultimately, my view has not changed.

The market is reading the wrong clock.

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

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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Previous write-ups on Calumet:

(Idea) Calumet Shares Sell Off Despite A Brightening Outlook

Special Situation: Calumet

(Idea) Calumet - The Next Special Situation Idea

(Idea) An Important Update On Calumet

By: Jon Costello

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

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

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

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

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

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

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

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

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

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

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

Montana Renewables Is Net-Long RINs

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By: Jon Costello

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

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

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

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

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By: Jon Costello

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

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

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

Stock Prices Are Stretched and Treasuries Are Compromised

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