Used, late-model versions of the RAV4 hybrid often list for more than their original sticker prices, even with thousands of miles on their odometers. In some cases, they cost more than a new 2026 model fresh from the Toyota Motor Corp. factory.

CarMax recently advertised a 2024 RAV4 Hybrid XSE with 29,000 miles for $46,998, which is higher than that trim’s original $38,735 sticker price.

The price inversion seems to defy a natural law of used-car economics. But it illustrates some of the most powerful forces driving the US auto market this year.

The Iran war sent gas prices surging, with the national average for regular well above $4 per gallon. Some car buyers have responded by snapping up used electric vehicles, which often sell at a steep discount from their original price. Others who are either unwilling or unable to go fully electric have turned to hybrids, which pair an electric motor with a gas-burning engine. Long considered a niche product in the US, they’re now highly coveted.

And for the moment at least, there aren’t enough new hybrid RAV4s to go around.

Production hit a lull last year as Toyota stopped building the fifth generation of the compact SUV and started making the sixth. 

The hybrid RAV4 gets upwards of 40 miles per gallon, well above the US new-car average of 27.2 mpg. It’s popular enough that Toyota discontinued all non-hybrid versions of the RAV4, starting this model year. And Brandon Wingate of Albany, Georgia, decided it was just what his family needed.

He and his wife were sold on its roominess, Toyota’s reputation for reliability and the hybrid’s promise of savings at the pump. Wingate paid $32,000 in February for a 2024 RAV4 with 44,000 miles on it — a car that listed for $38,735 when new. He drove about five hours across the state to test-drive it after spotting it online and was only able to haggle the dealer down $500 to compensate for a small window crack.

“There’s no negotiating anymore — you basically pay the asking price,” said Wingate, 42, an IT technician. “I’m just glad to have bought when we did, because prices for the same vehicle are up anywhere from $6,000 to $8,000 since then.”

Indeed, Carvana listed a 2025 RAV4 Hybrid Limited with 5,606 miles for $48,590. That’s a cool $6,040 above the manufacturer’s suggested retail price when it was new. It’s also more than the $43,300 sticker price of a 2026 Limited model.

Toyota, which began offering Americans a hybrid RAV4 option a decade ago, kept gas-electrics to a relatively low percentage of overall production volumes. That shortage helping to fuel high prices should end as Toyota scales up output of the new all-hybrid RAV4. “We have a very methodical cadence of ramping up to ensure high quality,” Cooper Ericksen, Toyota’s North American head of product planning and strategy, said in an interview.

For now, however, Toyota has less than five days’ worth of new RAV4 hybrids in its US showrooms, far below the company’s overall inventory of about 15 days.

“We’re selling every one we have in stock and have quite a few pre-sales” said Ryan Redding, general manager at Jim Norton Toyota in Tulsa, Oklahoma. Customers unwilling to wait often look for used RAV4s, he said, which means they’re also in high demand. “Most of the time, we don’t sell above the original MSRP,” Norton said.

Consumer Reports warns that new 2026 RAV4s are selling for about 4% more than their sticker prices. Managing Editor Jeff Bartlett, in a recent blog post, wrote that prices should edge down as production revs up, but “because elevated gas prices may keep interest in the RAV4 high, don’t expect discounts any time soon.”

With the average transaction price of a new car in the US now around $50,000, used cars have surged in popularity. So too have hybrids, which not only cut fuel costs but let drivers use highway carpool lanes in at least 12 states. Once limited to a handful of models like the original Toyota Prius — with a shape often compared to a cheese wedge — hybrid drivetrains are now available in most every class of passenger vehicle, including the Ford Motor Co. Maverick pickup, the Kia Corp. Carnival minivan and Stellantis NV’s Jeep Cherokee SUV.

Some of those hybrids command high prices used, although not as consistently as the RAV4.

Carvana, for example, lists several Honda Motor Co. hybrids with asking prices near their prices when newly sold. It recently advertised a 2024 CR-V Hybrid Sport Touring version with 14,000 miles for $40,590, just below the original base sticker of $41,595. Data from CarGurus, a website that lists vehicles for sale by dealers, show that two of the three types of 2025 CR-V hybrids list for at least 90% of their original MSRP, and all three trims of the 2024 model year retain 80% of their initial value.

All used RAV4 hybrids from the 2024 model year onward command prices of at least 90% of their initial MSRPs, according to CarGurus. Of the seven hybrid trims offered in the 2025 model year, four now list for more than their original sticker prices.

“Toyotas are in general tough to find, and hybrids are tough to find,” said Kevin Roberts, director of economic and market intelligence at CarGurus Inc. “If you’re struggling to find a new RAV4 hybrid, you might pay more for any used one you can get your hands on.”

While unusual, Roberts said that’s not unprecedented. Used-car prices spiked during the Covid-19 pandemic, when automakers cut new car production and removed certain features like heated seats due to chip shortages.

Prices for used hybrids, however, have climbed high enough this year that some buyers say they can’t justify the expense — even knowing they’d save on gas.

Peter Aviles, a retired home inspector based in Fort Lauderdale, tested a 2021 RAV4 hybrid in April but instead bought a gas-only 2022 version for his vacation home in Puerto Rico. He wanted a RAV4 because of its reputation for quality and high resale value, but he wasn’t willing to pay the premium for a hybrid.

“It gets good enough fuel economy,” Aviles, 75, said. “And it can handle the potholes.”

(Updates with car listing in third paragraph.)

©2026 Bloomberg L.P.

State producer Saudi Aramco will lower the price for Arab Light crude for buyers in Asia next month by $6 a barrel to a premium of $9.50 more than the regional benchmark, according to a price list seen by Bloomberg. A $5 reduction was expected by refiners and traders in a Bloomberg survey.

The Saudis lowered prices for all grades by $10 a barrel to customers in Europe and the Mediterranean, while prices for varieties for North America were shaved by $2 a barrel.

As the US and Iran drag out talks aimed at extending a ceasefire in their conflict, global oil markets remain disrupted by the continued closure of the Strait of Hormuz. With tankers stuck inside the Gulf and empty vessels prevented from entering to pick up new cargoes, the region has drastically scaled back production, shutting in fields and slowing or halting refineries.

Aramco has been the mainstay of Gulf crude exports because it has been diverting oil through a cross-country pipeline to the Red Sea port of Yanbu. That allows the company to ship as much as 70% of its pre-war exports while supplying crude to the country’s west coast refineries.

Those facilities have been pumping out products like diesel and jet fuel as Aramco seeks to capitalize on margins that have surged for refiners. 

The profit from turning crude into products remains high, but slipped at the end of May, possibly reflecting declining demand as consumers deal with higher prices. Aramco traditionally prices its crude to shadow refiners’ profits, potentially explaining its decision to cut official prices for July.

The OPEC+ producers group, led by Saudi Arabia and Russia, decided to raise production targets for July by 188,000 barrels a day at a meeting on Sunday. The increase is largely symbolic with Hormuz still mostly shut, though it indicates that the group won’t restrict members from pumping oil onto markets once the Iran conflict is resolved. 

©2026 Bloomberg L.P.

Vulnerability exposed

The conflict again highlighted the vital importance and vulnerability of the Strait of Hormuz. It accounts for about 20% of global LNG transit, so a collapse in trade through the route has widespread ramifications.

The world’s LNG market was nearing a turning point after the disruption from Russia’s war with Ukraine. Prior to the Iran conflict, Qatar shipped 110 bcm of LNG annually to Asia, Europe, and increasingly Africa. But this relied on robust transit routes. About 20% of the world’s LNG is supplied by Qatar, but attacks on the Ras Laffan refinery have affected about 17% of the country’s export capacity. Repairs could take several years in a worst-case scenario, slashing revenue by about $20 billion a year. Production disruptions will lead to higher costs or shortages for countries reliant on Qatari LNG, especially in price-sensitive Asian and European markets. Asian LNG prices more than doubled to three-year highs, including a surge in the Japan-Korea Marker (Platts JKM) reported by Bloomberg in early March.

As hostilities began, European natural gas prices soared above 60% on the benchmark Dutch TTF (Fastmarkets); from €30 per MWh to hit a high of €74 per MWh, reflecting panic over tightening LNG supplies.

It was feared an escalation of the conflict could increase the likelihood of commercial disputes among LNG market participants in the ensuing months. And sustained high gas prices might yet prove inflationary globally, reduce worldwide GDP growth, and push major economies into a global recession. 

The fragility of peace: the ceasefire and the LNG crisis

When a ceasefire came into place on the ground in the Middle East, energy markets reacted with predictable volatility, seeing oil and gas prices plunge by as much as 16%. However, the headline figures mask a far more stubborn reality. While a continued cessation of hostilities was a welcome development, as a structural fix for the global natural gas and LNG market, the initial 14-day window was simply a tactical pause in a much larger strategic crisis.

Estimates suggested that approximately 15 LNG-laden tankers could transit the Strait of Hormuz over that fortnight. This represents roughly 1 million tonnes (Mt) of LNG — a volume that, while significant in isolation, is a mere fraction of the 7-8 Mt typically exported by Qatar in a standard month. Maritime trackers reported just five LNG carriers transited the Strait between 22 April and 7 May.

The fundamental issue is one of industrial inertia. Qatar’s massive Ras Laffan production complex is not a tap that can be turned on at a moment’s notice.

For Asia — the centre of global gas demand growth and LNG infrastructure investment — the implications are especially acute. A full operational restart requires multiple weeks of technical lead time. Furthermore, the spectre of permanent infrastructure damage remains; even in a best-case scenario, QatarEnergy may be looking at a 17% capacity reduction, with only 12 of its 14 liquefaction trains currently viable. For an industry built on the principle of reliable, high-volume energy addition, this level of impairment is a significant blow to global energy security.

Market floors and the Hormuz premium

Beyond the physical production, the economics of transit through the Strait of Hormuz have fundamentally shifted. Even the possibility of additional transit costs through the Strait of Hormuz has injected a new geopolitical risk premium into LNG pricing, with estimates of tolls as high as $2 million per passage adding roughly $0.50/MMBtu to cargo costs, creating a new friction-heavy environment. When compared to the standard $1.50/MMBtu cost for a 28-day journey to Europe, this geopolitical security premium is a substantial addition for the industry if it plays out.

While ICIS TTF gas prices retreated towards the pre-war €30–32/MWh range (the 52-week low was €26.53) before settling around €46/MWh in mid-May, any geopolitical tax on Hormuz transit will lead to cheap gas becoming a thing of the past. This pullback reflects short-term positioning rather than a resolution of underlying supply risks.

A 150 TWh reduction in gas-to-power demand for the remainder of 2026 was previously estimated due to high prices; should prices stabilise at lower levels, a strong power sector reaction in Europe could quickly absorb the surplus.

Against that context, the industry is looking forward with a sense of energy realism. The initial two-week peace deal, for instance, was too brief to resume critical work on the North Field East (NFE) expansion. 

The Asian gas equation

Before the conflict, Gulf producers collectively supplied almost a fifth of global LNG. Long-term constraints risk major shocks to Asian customers, as several countries are heavily dependent on those imports. As supply rapidly leapt from surplus to shortage, Asia’s stock markets have repeatedly fallen.

The EIA said 83% of LNG shipped through the Strait in 2024 went to Asian markets: China, India, Japan, and South Korea, accounting for 59%. “This conflict highlights that oil and gas supply chains are inherently unreliable and vulnerable to geopolitical instability,” said Zero Carbon Analytics. “Of all commodities, LNG is the most exposed to geopolitical shocks, with conflicts magnifying inherent volatility.”

"Now everything is up in the air, growth in energy supply in 2026 is going to be much lower than everybody expects. If the crisis extends, there might be a point at which there is no growth at all."

- Anne-Sophie Corbeau
Global Research Scholar at the Center on Global Energy Policy (CGEP) at Columbia University and Co-Chair of the Gastech Governing Body

Before the current escalation, regional assumptions about long-term gas demand were built on an expectation of ample and reliably traded LNG supply. All of this challenges Asia Natural Gas & Energy Association’s prediction that Asia Pacific natural gas use would more than double by 2050. LNG consumption in the region increased by 35% between 2015 and 2023 (Ember Energy).

Simon Flowers, Chairman and Chief Analyst at Wood Mackenzie, cites a 6.5 million-tonne-per-month loss in Gulf export volumes. “The maths is simple,” he said. “No Gulf exports beyond four or five months will mean annual LNG supply falls, upward pressure on prices through 2026 and demand destruction, particularly in Asia.”

"No Gulf exports beyond four or five months will mean annual LNG supply falls, upward pressure on prices through 2026 and demand destruction, particularly in Asia."

- Simon Flowers
Chairman and Chief Analyst, Wood Mackenzie
and Gastech Executive Committee Member

Anne-Sophie Corbeau, Global Research Scholar at the Center on Global Energy Policy (CGEP) at Columbia University, says a price drop was expected possibly this year, based on additional LNG due in 2026 and 2027. “Now everything is up in the air,” she said. “Growth in energy supply in 2026 is going to be much lower than everybody expects. If the crisis extends, there might be a point at which there is no growth at all.” 

Short-term constraints and market responses

Conflict has again sharpened attention on the geopolitical and energy security implications of LNG production and transit. Asian buyers have been scrambling to manage the shortage. Consultancies such as S&P Global Energy have cut global supply forecasts by up to 35 million tonnes — roughly 500 cargoes.

One response has seen European importers outbid, leading to supplies being redirected to Asia. This again reveals Europe›s vulnerability, which sought to diversify away from Russian gas but is now exposed to reliance on imported LNG, much of it from the Gulf.

Governments and companies confronting uncomfortable realities are potentially rethinking energy security doctrines to maintain economies and growth.

In some Asian states, particularly China and India, fossil fuels such as coal could prove critical for short-term energy security.

Of all commodities LNG is the most exposed to geopolitical shocks, with conflicts magnifying inherent volatility.

In the medium to longer term, buyers may need to reassess the balance between price and the security of LNG supply. For example, Australian LNG costs more but offers shorter, less volatile shipping passage to Southeast Asia. However, existing project production is mostly already contracted (Norton Rose Fulbright). Meanwhile, multiple Asian countries competing simultaneously for limited alternative cargoes push spot prices higher.

In a market now defined by absolute scarcity rather than elasticity, even modest volumes have an outsized influence on price formation. Flowers explains that 3.5b cubic feet per day could be added, mainly from the most LNG import-dependent producers. “This is only 0.8% of global supply, but more crucially, it is 30% of the LNG curtailed in Qatar,” he said. “The gain is not enough to prevent serious price consequences, but enough to potentially soften some of the blow.”

Diversifying supply and reducing exposure

Trends first accelerated by Russia's invasion of Ukraine are now being stress-tested by renewed instability in the Middle East. 

Disruption caused by Russia’s war with Ukraine prompted new LNG projects, mainly in the US. Wood Mackenzie says these could add 35 million tonnes to global supply this year (an 8% increase).

The US was the world's largest LNG exporter in 2023, according to the Reuters, and India's third-largest LNG supplier last year. 

Gas supply disruptions have prompted Pakistan's government to look to coal, hydropower, and nuclear power, while price volatility and shipping uncertainty are likely to sharply increase power costs in Bangladesh, raising subsidy requirements and increasing the likelihood of load shedding and reduced industrial supply.

In a market now defined by absolute scarcity rather than elasticity, even modest volumes have an outsized influence on price formation.

Singapore commissioned an LNG terminal and is developing a second to expand regasification capacity and reduce exposure to supply disruptions. However, this heightens sensitivity to global LNG prices.

At least one report suggests Japan may now ramp up coal-fired power generation amid an LNG crunch.

Alternatives for South Asian and Southeast Asian LNG buyers include Papua New Guinea, Indonesia, Malaysia, and Brunei, offering regional proximity, existing infrastructure and trading history. Barriers include limited spare capacity, declining production in some legacy fields, and competition with domestic demand.

Canadian West Coast LNG offers direct access across the Pacific and a stable regulatory environment. However, near-term volumes are limited. 

• This Market Outlook report was produced for Gastech. For more information and to register as a delegate, visit Gastech Bangkok 2026.

The oil market possibly sees this conflict balance as being once again on the testbed and reacts accordingly with nervousness. Beyond the geopolitical noise, the oil market proves resilient and digests the supply shock well for now. Several vessels transited Hormuz over the weekend. We sense a greater degree of trade pragmatism, mirrored in the different bilateral deals concluded between Gulf-locked sellers and mostly Asian buyers within Iran.

Transits growing over time

The current hostilities likely lift hesitance in the short term, but the common interests, and especially the profit opportunity, should keep these transits growing over time. Oil tends to find its way from sellers to buyers over time, especially when prices are elevated. The oil market’s deficit is closer to 5% than to 10%, thanks to the partial Hormuz flows, the alternative routes, and some demand curtailment, which provide breathing room to deal with the trade disruption with oil supplied from storage until late this year.

While a lasting trade disruption remains the bear scenario, our base case is a gradual easing, following similar dynamics to the early 80s, likely spiced up by some eventual US-Iran dealmaking. Today’s hostilities threaten the past weeks’ conflict balance due to the risks that come with hot-headed politics and the fact that the latest hostilities challenge the US-Israel alliance. While we are keeping a close eye on this, we stick to our cautious view and see oil prices heading lower beyond the summer.

Seven nations led by Saudi Arabia and Russia will raise their collective target by 188,000 barrels a day next month, continuing the process — if only on paper — of restarting production halted several years ago, the Organization of the Petroleum Exporting Countries said in a statement on Sunday after a video conference. 

With the Strait of Hormuz largely closed by the Iran war and Middle East producers forced to cut output, the OPEC+ decision remains theoretical for the time being. It could become relevant again when the waterway reopens, with buyers clamoring for barrels to replenish the world’s depleted oil inventories.

“At this stage we are basically talking about hypothetical future scenarios with the bulk of the barrels stranded,” said Helima Croft, head of commodity-markets strategy at RBC Capital Markets LLC.

While Russian shipments aren’t directly affected by the war, its crude production has also been challenged, falling to a 10-month low in May as Ukraine intensified strikes on its oil infrastructure.

A surge in US supply and diminished Chinese buying have prevented crude oil prices from spiraling out of control so far, though fuels such as gasoline, diesel and jet fuel have nevertheless surged during the conflict. 

That’s squeezing consumers worldwide and heightening the risk of an economic downturn. Still, markets haven’t rallied as much as feared while China dials back imports, major consumers tap emergency stockpiles and US President Donald Trump repeatedly signals an imminent peace deal.

The seven OPEC+ nations engaged in monthly quota adjustments will next meet on July 5. Besides the Saudis and Russia, they consist of Iraq, Kuwait, Kazakhstan, Algeria and Oman.

The UAE announced its departure from the organization effective May 1, ending six decades of membership. Abu Dhabi had long been frustrated that OPEC’s quotas prevented it from deploying new investments in production capacity.

For most of the past year, key OPEC+ nations had been restoring output halted several years ago, when the alliance was trying to stave off a surplus and shore up prices. They’ve continued the process since the war started, even though the conflict prevents many of them from raising production. 

With the quota increase for July, the group will have nominally restored almost 90% of two layers of production halted in 2023. Last month, delegates said the group had a plan to complete that chunk with increases from July to September. Those supplies amounted to 3.85 million barrels a day at the time, though the volume has been reduced slightly as a result of the UAE’s exit.

A third layer, which equated to 2 million barrels a day when it was taken offline in 2022, is due to remain shut down until the end of year. Delegates said last week it could be fast-tracked, but even then most of the oil wouldn’t materialize. 

Pledged supply increases over the past year have fallen significantly short of the advertised amounts as a combination of under-investment, aging oil fields and sanctions have eroded production capacity in many OPEC+ members. 

The full OPEC+ coalition, which now comprises 21 countries following the UAE’s departure, will hold its next ministerial meeting on Nov. 29.

©2026 Bloomberg L.P.

It’s now been more than three months since the waterway was effectively blocked, creating the worst supply shock in modern history. But a slew of workarounds is keeping crude oil below $100 a barrel, defying many of the industry’s grimmest forecasts for prices as high as $200.

A combination of record US exports, a sharp and unexpected slowdown in Chinese demand and a steady trickle of crude still finding its way through the strait has helped absorb much of the shock from the loss of more than 10 million barrels a day of Middle Eastern supply. A pre-war surplus has also eased the blow. 

“People thought it was going to be a lot worse,” President Donald Trump said Friday. “Today I looked at $96 a barrel, people thought that was going to be $300 a barrel.”

All eyes now are on how long those buffers can hold, while the question of when flows might resume through the strait, and where oil prices are headed, have become the biggest wild cards for the global economy.

One of the biggest surprises for the oil market has been China, the world’s largest importer. It slashed inbound shipments by almost 40% in May compared to last year’s average, according to Vortexa Ltd. The reduction is enough to offset anywhere between a third and a fifth of the barrels lost to the war, depending on the estimates used.

At the same time, the US has emerged as the world’s most important swing supplier since launching strikes on Iran in late February. American crude and fuel exports in May were more than 2 million barrels a day higher than the average for all of last year.

Other emergency measures have also eased the strain. Governments around the globe coordinated a historic release of strategic reserves, while Gulf producers rerouted shipments through alternative export routes. Some tankers continued moving cargoes via the strait despite the risks, using increasingly opaque methods to avoid military threats. 

“Over three months into this conflict, the world has proven surprisingly resilient,” Maria Angelicoussis, chief executive officer of Angelicoussis Group, the largest Greek shipowner by number of vessels on the water, said in rare public remarks this week. “Commodity prices are up by 50% or 60%, Asian LNG prices by 90%, but they’re not at the sky-high levels that at least I would have personally expected.”

For now, oil trading well below $200 a barrel, a level many analysts initially feared, has left Trump wiggle room in negotiations with Iran, even as he repeatedly insists a peace deal is within reach. But a renewed and sustained price spike would add more pressure on the White House to strike a deal quickly to stem a hit to the global economy. 

Global inventories are drawing down at a record pace, leaving the market increasingly vulnerable to fresh disruptions. With spare supplies dwindling, even relatively small outages could trigger violent price spikes. 

“Each week that goes by, the system is tightening by 70 to 80 million barrels. You can’t do that forever,” said Greg Sharenow, who helps manage nearly $24 billion as head of Pacific Investment Management Co.’s commodity portfolio investment team. “Over the course of the next few months, generously speaking, you’ll really be staring at a system that could be lacking flexibility because the buffers have been really depleted.”

American Boomtimes

US oil production has boomed to record highs in recent years thanks to the shale revolution that began over a decade ago, turning the country into a net exporter of crude and refined product.

The abundance of domestic energy has allowed President Trump to make geopolitical decisions and moves that would’ve once been considered unthinkable — not just starting a war against Iran, but also the seizure of Venezuelan President Nicolas Maduro.

Washington has also used its energy muscle to help stabilize markets. The Trump administration pledged to release 172 million barrels from the Strategic Petroleum Reserve as part of a broader effort by advanced economies to help offset lost supplies. So far it has done so at a rate few thought possible — in one week last month the stockpile declined by 1.4 million barrels a day. Nearly half of the barrels released so far have sailed to Europe and other overseas destinations.

The twin forces of US exports and depressed Chinese buying are in part why the world’s most important physical crude price, Dated Brent, has retreated below $100 a barrel after surging to a record above $140 a barrel in the early phase of the war. The most recent expiry period — the vital window in which real-world and futures prices converge — showed little indication of a supply shortage. 

Now, however, the limits of some of the workarounds are coming into focus. Overall oil inventories in the US shrank to the lowest level in more than two decades last week. Emergency reserves have little oil to spare and fuel stockpiles are facing critical lows as peak summer demand months approach.

“We’re not capable of sustaining these exports,” said Pimco’s Sharenow, adding that inventories at the critical storage hub in Cushing, Oklahoma, are approaching operational lows.    

At the same time, domestic refiners are running their plants harder than usual to meet fuel demand and competing for barrels, sending the premiums for US crude delivered in Asia higher relative to available Middle Eastern supplies, according to traders.

The Trump administration has made other strategic moves to help stabilize markets. Notable among those has been a waiver for some sanctioned Russian oil, making it easier for Indian processors, in particular, to boost purchases. 

Russian flows to India, the world’s third biggest importer of crude, averaged about 1.76 million barrels a day in May, 63% higher than in February.

China’s Return

Many traders see China’s eventual return to pre-Iran war oil purchasing rates as the key to predicting when oil prices finally lurch higher.

The voracious appetite of the world’s largest crude importer — over 10 million barrels a day since the start of the war in Ukraine — has been curbed for now. That drop-off has come in part as the nation stopped growing its giant strategic stockpile, which has ballooned in recent years.

Also quelling demand is China’s pivot toward producing chemicals from raw materials like coal instead of oil, according to analysts. Booming domestic sales of electric vehicles is also curbing gasoline consumption.

The country’s refinery throughput in May and June is seen languishing at around 13 million barrels a day, a monthly run rate last seen during the early stages of the pandemic in 2020, according to estimates by Kpler and Energy Aspects Ltd. Throughput averaged 14.8 million barrels a day last year.

“China’s backing off from the crude market has played a crucial role in attempting to rebalance the global market, which has helped cap oil prices,” said Warren Patterson, the head of commodities strategy for ING Groep NV in Singapore. “The extent of which has taken most of the market by surprise.”

Hormuz Flows 

Persian Gulf oil producers had workarounds that quickly saved the market in the early days of the war. Saudi Arabia’s East-West pipeline shipped millions of barrels a day to the Red Sea, while the United Arab Emirates has been piping barrels to the port of Fujairah outside the gulf. 

There’s also been a trickle of vessels willing to transit the strait, either as part of government-to-government deals, risk-taking enterprise or, more recently, with help from the US. 

Still, transits have plunged to two or three every day compared to nearly 100 prior to the conflict, according to shipping tracking data. Visibility on commercial shipping through the waterway is limited by ongoing GPS jamming and tracking disruptions.

An official familiar with US Central Command operations put the count much higher at nearly 1,000 commercial vessels crossing in and out of the Strait of Hormuz in the last two months, according to a Bloomberg report Friday.

“As a bare minimum of what counts as a ‘meaningful recovery’ I think that we would need to see a full week averaging 20 ships per day — and that’s not realistic until there is a durable US-Iran settlement, which keeps getting pushed out,” said Pavel Molchanov, an analyst at Raymond James.

Another factor keeping a lid on prices has been Trump’s relentless jawboning, making it hard for even the most bullish traders to hold long positions for prolonged periods of time. 

Open interest in Brent crude futures is the lowest since August as elevated market volatility forces traders to roll back risk exposure.Steep price drops on the prospect of peace have pushed many oil bulls to the sidelines, leaving them to hold small positions for very limited periods of time, several traders said. 

The lack of risk-taking has helped keep a lid on financial flows, while supply levers have averted the worst hit to the market. The question now, is whether that can last without apeace deal. 

“It’s basically this anticipation that there’s a solution just around the corner,” Tom Baker, head of Vitol Bahrain, a unit of the world’s top independent oil trader, said at a conference this week. But no matter how quickly production is restored, “you’re still left with a hole — whatever you want to call it — a billion barrels of oil that is missing.”

©2026 Bloomberg L.P.

Military analysts measured the number of ship passages since a ceasefire took effect between the US and Iran on April 8 using continual air, sea and space surveillance deployed as part of the war against Iran, the official said, asking not to be identified to discuss data that hasn’t been made public. The bulk of the vessels are large cargo and container ships and the figure doesn’t count smaller craft, such as traditional dhows, they added. 

The figure is still far below the more than 100 ships passing daily through the vital waterway for oil and gas from the Persian Gulf before President Donald Trump launched a war against Iran in late February, which effectively shuttered the Strait of Hormuz and sent global energy prices soaring. 

But the new US tally suggests commercial traffic in the strait has been at least slightly busier than previously believed. A Bloomberg tally of ship-tracking data using transponders counts just over 650 transits since April 8 — 402 outbound and about 260 inbound. 

The US count likely reflects — at least in part — the rising number of so-called dark transits ships are making with transponders turned off to help avoid detection by Iran, as US forces attempt to get traffic moving again amid a rising outcry about the worsening impact of the strait’s closure on the global economy.

Asked on Friday how much oil was getting out of Hormuz, Trump replied: “A lot.”

“I don’t want to say how many, but a lot,” the president told reporters traveling aboard Air Force One. “A lot of oil is coming into the world that people don’t even know about. And that’s why it’s at $97 a barrel instead of $300 a barrel.”

US and Israeli airstrikes on Feb. 28 quickly prompted Tehran to shutter the strait with threats to sink commercial vessels, a move that — along with attacks on regional energy infrastructure — has caused global energy prices to soar and fueled inflation, piling pressure on the White House to end the unpopular war. 

The Strait of Hormuz has also emerged as a key sticking point in US-Iran talks to end the conflict, with Tehran repeatedly suggesting it wants to retain control — and possibly toll — the strait, and US officials insisting the strait remain free and open.

Why Strait of Hormuz Is at Heart of US-Iran Stalemate: Explainer

In recent weeks, the US military has quietly restarted efforts to get more commercial traffic moving through the strait, helping commercial vessels navigate along a sea mine free route closer to the Omani — rather than Iranian — coast, and protecting them from Iranian attacks if needed. 

The effort follows a previous US military attempt to protect vessels exiting Hormuz in early May, which was quickly abandoned after Iranian attacks on the ships leaving Hormuz spooked other shipping companies from attempting it. 

But traffic appears to be continuing, despite a flareup earlier this week, when Iran launched a wave of drones and missiles at Kuwait’s international airport — killing one and injuring more than 60 people — and at US forces stationed in Bahrain. US Secretary of State Marco Rubio said the attacks were because of the US helping ships move through Hormuz. 

US Central Command issued a statement saying its forces shot down Iranian attack drones aimed at “civilian mariners that were rightfully transiting regional waters.”

US forces are communicating with commercial shippers preparing to enter or transit the Strait of Hormuz and the Persian Gulf through a longstanding ecosystem that involves radio, telephone and chat that was previously developed by the current Centcom commander Admiral Brad Cooper, the US official said. Cooper headed US Navy forces in the Middle East between 2021 and 2024 as 5th Fleet commander, and would regularly convene conference calls with shipping companies to share best practices, the official added.

Today, the US Navy is passing information on transit routes, timing considerations and potential Iranian threats with vessels going into and out of the Persian Gulf via operations centers in the region and Centcom’s main headquarters in Tampa, Florida, the official said.

The communication is informed by continuous imagines and other data gathered by US surveillance aircraft flying over the region as well as systems from Navy vessels. The aircraft include Boeing Co. P-8 reconnaissance aircraft, fifth-generation F-35 warplanes, MQ9 Reaper surveillance drones and satellite coverage, the official said.

©2026 Bloomberg L.P.

The Alaska Industrial Development and Export Authority, a state agency, and Anchorage-based Hex Energy were the sole entrants in the auction for nearly 690,000 acres of oil and gas drilling rights. It was the Interior Department’s first lease sale in the refuge since lifting drilling restrictions imposed by former President Joe Biden. 

It was a key test of the oil industry’s appetite to drill in the rugged frozen tundra, long prized for its oil and gas potential but burdened by political uncertainty, environmental opposition and logistical challenges.

The sale was the first of four lease sales required under President Donald Trump’s tax-and-spending law, the One Big Beautiful Bill Act, which mandates at least four auctions in the area by 2035. It comes as Trump seeks to make tapping Alaska’s vast natural resources a key part of his energy agenda.

Combined, the Industrial Development and Export Authority and Hex Energy bought leases for five tracts through the sale.  

Trump signed legislation during his first term ending a four-decade ban on energy development in the refuge, which is estimated to contain as much as 11.8 billion barrels of recoverable oil. The protected area occupies a section of northeastern Alaska roughly the size of South Carolina.

Major oil companies largely steered clear of the first two lease sales that followed. An auction held weeks before Trump left office in January 2021 drew bids from two oil developers and Alaska’s state-owned economic development company. A second sale in January 2025 under the Biden administration resulted in zero bids, though oil industry representatives and Alaska officials argued restrictive lease terms artificially discouraged interest. 

Some analysts are skeptical about the prospects for drilling in the region. 

“Production will be challenging, and the prospect that permits will be canceled as soon as a new administration takes over is likely given that this is an easy way for a new administration to make a show of its environmental commitment,” said Ellen Wald, a senior fellow with the Atlantic Council Global Energy Center and the president of Transversal Consulting.

Cooper Freeman, Alaska director for environmental group Center for Biological Diversity, called the auction a “flop of a lease sale.”

“This stunning yet predictable failure shows that drilling in this pristine landscape is a dead end for the fossil fuel industry,” Freeman said in an emailed statement. 

Still, a March lease sale in the National Petroleum Reserve in Alaska drew a record $163 million in bids from established operators like ConocoPhillips, as well as companies such as Exxon Mobil Corp., which last drilled an exploratory well in the state in the early 1990s. Shell Plc, which abandoned Arctic exploration after a costly unsuccessful search for crude waters north of Alaska, partnered with Repsol SA to secure over 40 leases. 

Environmental groups and some indigenous communities, including Gwich’in, which consider the coastal plain sacred, argue drilling threatens Arctic foxes, polar bears, caribou, musk oxen and migratory birds. 

“The diverse and sacred landscape of the Arctic Refuge is unlike any other and should never be sacrificed for oil and gas drilling,” said America Fitzpatrick, a program director with the League of Conservation Voters. “Any companies considering drilling in the Arctic Refuge would be doing so against the majority of people who support protecting this critical landscape.”

Meanwhile, local leaders, including those in Kaktovik, the only village within the refuge, support development, arguing it’s necessary for the region’s economic well-being. 

Alaska crude production has steadily declined from a peak of 2 million barrels a day in 1988 to roughly 417,000 barrels a day in March, according to the Energy Information Administration. The agency projects output will rise to 450,000 barrels a day this year and 500,000 barrels a day in 2027 as new developments begin producing.

(adds comment from environmental group in 10th and 11th paragraphs.)

©2026 Bloomberg L.P.

The small reactor being developed by Antares Nuclear Inc. participating in an Energy Department pilot program reached “criticality,” the agency said in a statement. The milestone occurs when a nuclear chain reaction becomes self-sustaining enough to produce a steady release of energy. 

The achievement shows that the Trump administration’s effort to remove regulatory barriers is helping demonstrate the viability of new nuclear technologies. 

The White House is pushing for wider deployment of both large, conventional reactors and smaller ones from companies like Antares. While the Antares system is still far from being used in a commercial capacity, achieving criticality is a notable step toward that goal. The company, which is initially targeting military applications, said it expects to see its systems deployed in the field by the end of 2028.

“This initial criticality is the first step on a roadmap toward producing electricity,” Jordan Bramble, Antares’ chief executive officer, said during a video briefing Friday. 

The Energy Department has set a goal of achieving the milestone in at least three test reactors by July 4 and selected projects from Antares, Oklo Inc., Aalo Atomics Inc., Atomic Alchemy Inc., Deep Fission Inc., Last Energy Inc., Natura Resources LLC, Radiant Energy Inc., Terrestrial Energy Inc., and Valar Atomics Inc. to participate in a program designed to expedite development and authorization of reactors. 

(Updates with comment from CEO in penultimate paragraph.)

©2026 Bloomberg L.P.

Voltage fluctuations were among the key causes of the nationwide outage, and since then, grid operator Red Eléctrica has been keeping more gas-fired plants online to maintain stability. The average daily minimum output from gas plants has risen about 40% from pre-blackout levels, according to Bloomberg calculations based on ENTSO-E data.

While Spain has taken measures to strengthen the resilience of the energy system since the blackout, it would “benefit from taking further steps to enable its transmission system operator to move away from the current increased use of gas power plants to maintain voltage stability,” the commission said in a country report earlier this week.

The country has one of Europe’s most renewable-heavy electricity systems, but its reliance on solar and wind makes the grid more complex to manage during disturbances. While traditional sources of power generation such as natural gas, nuclear and hydro continually help regulate the grid’s voltage, most wind and solar plants currently do not.

Spain’s move to using more gas-fired generation is meant to be a temporary measure, but it’s not clear when it will end. Alternative systems to help stabilize the grid are expensive and take time to deploy.

Spain’s Ecological Transition Ministry said it’s already taking action to reduce the use of gas-fired power plants in the system, and that the implementation of the operation to strengthen the system is the responsibility of Red Eléctrica. Red Eléctrica didn’t immediately respond to emails seeking comment.

“We expect the reinforced operating mode to persist because the political focus on system security risk is still high, with a general election coming in 2027,” said Alexis Stavropoulos, a Spanish power market expert at consultancy Baringa Partners.

The country is increasing investments in energy storage to improve flexibility. By 2030, Spain hopes to have 22.5 gigawatts of storage, but as of February 2026 it stood at 8.15 gigawatts, according to the European Commission’s country report.

Last week, the Commission also approved a new €9 billion mechanism to help Spain procure additional backup power supplies as it continues to expand renewable generation.

©2026 Bloomberg L.P.

LS Power is discussing paying more than €4 billion ($4.7 billion) for the unit, one of the people said, asking not to be identified discussing confidential information. A deal may be announced in the coming days or next week, the people said. Talks may drag on for longer and could still fall apart, they added.

A spokeswoman for EDF said the company can’t comment on an ongoing process, while a representative for LS Power declined to comment. 

The EDF unit for sale had 6.1 gigawatts of solar and wind in operations in the US, Canada and Mexico at the end of last year, and a further 19.2 gigawatts under development.

A deal would further reshape the portfolio of closely held LS Power, which recently sold some of its gas-fired power plants to NRG Energy Inc. for about $13 billion in cash and NRG stock, while it acquired some renewable assets from Algonquin Power & Utilities Corp. The New York-based company also agreed this year to buy some electric-generation assets from Constellation Energy Corp. for about $5 billion, and purchased some onshore wind assets from BP Plc for an undisclosed amount.

Deal activity has picked up in the US power industry as demand surges for electricity. Manufacturers, homes and especially data centers are all clamoring for more power, which is driving up prices. The tech industry continues to chase ambitious plans to add computing capacity across the US with the biggest Silicon Valley companies forecasting more than $700 billion of capital spending this year alone. 

Meantime, the French state-owned utility is raising funds to help finance the construction of nuclear reactors in France and the UK to replace part of its aging atomic plants. That investment — costing tens of billions of euros over the next two decades — coincides with falling French power prices, putting the utility’s finances under pressure.

According to the group’s annual document, EDF expects its annual investments to climb to €28 billion per year in the 2026-28 period — up from €24 billion last year — as it prolongs the lifetime of its nuclear reactors, and boosts spending on the construction of new atomic plants and on the upgrade of France’s power grid. 

While EDF managed to reduce its net financial debt to €51.5 billion last year, the increase in capital expenditure comes as the utility foresees a slight drop in profits this year due to falling power prices.

To limit cash outflows, EDF outlined plans to save €1 billion on annual expenditure by 2030, and recently sold a gas-fired power plant in Brazil for about €230 million. The company is also seeking to divest its renewable energy assets in China, and part or all of a small unit that’s developing hydrogen projects.

To raise more funds, the French nuclear giant is also considering selling a minority stake in its Italian unit Edison SpA. However, the plan is being disrupted by the war in the Middle East and the damage to Qatari gas-export plants that supply large volumes of the fuel to Edison.

(Adds details on EDF asset sales in last two paragraphs)

©2026 Bloomberg L.P.

Brent traded around $95 a barrel after falling 2.8% on Thursday, while West Texas Intermediate was near $93. President Donald Trump said that talks with Iran were going well, despite Tehran-backed Hezbollah rejecting a US-brokered ceasefire deal between Israel and Lebanon.

WTI has gained more than 6% this week after uncertainty over the progress of the negotiations eroded some of the earlier optimism for a deal that would lead to a resumption of oil flows through the strait — which carries about a fifth of the world’s crude and liquefied natural gas in peacetime. Futures are still down about a fifth since early April — when the US and Tehran agreed to a ceasefire that ended more than five weeks of fighting.

“The move in WTI from pre-ceasefire highs of $110+ to current levels in the low-$90s was the proverbial low-hanging fruit — signaling the oil market’s relief that all-out war is over, and the region’s oil industry infrastructure has been mostly unscathed,” said Pavel Molchanov, an analyst at Raymond James. “Further price declines will hinge on meaningful recovery in Hormuz shipping volumes.”

There was no sign of progress in talks between Tehran and Washington, with Israel’s continued military strikes in Lebanon becoming a major sticking point. Asked by reporters Thursday in the Oval Office about Hezbollah’s rejection of the Lebanon ceasefire, Trump said “they didn’t reject me” and claimed “they called us” to discuss a cessation of hostilities.

In the Middle East, Oman’s main crude oil export terminal at Mina Al Fahal has delayed loadings after an explosion disrupted port operations, according to traders familiar with the matter. The facility sits outside of the Strait of Hormuz and is one of the few remaining points Middle Eastern crude oil can still be loaded amid the war. 

“The mixed messaging on peace talks is not really bearish for oil yet. It probably just stops prices from running too far on the upside for now,” said Charu Chanana, chief investment strategist at Saxo Markets in Singapore. “Traders can take out a bit of the war premium when headlines sound constructive, but until there is real progress on the ground, it is hard to say the risk premium is gone.”

On Thursday, Trump said in a social media post that he’s “right in the middle of my final negotiations to end the War with the Islamic Republic of Iran.” He didn’t elaborate on the talks, using the post to blast a vote by the Republican-led House of Representatives to halt the war. 

©2026 Bloomberg L.P.

The main message from executives at the world’s largest solar conference in Shanghai this week was an acknowledgment that the sector should shift to new areas of growth, like batteries or even projects in space. A relentless race to outdo rivals has created a glut of manufacturers that, while helping drive down solar-panel prices and fueling a global clean-energy boom, has left producers mired in losses for more than two years.

“The entire industry is locked in a zero-sum game, with only one outcome — fighting in the mud leaves no winner,” Zhu Gongshan, chairman of GCL Technology Holdings Ltd., said at the SNEC PV+ conference. “The past strategy — centered on expanding production, cutting prices, and chasing scale — has reached its physical limits.”

Chinese solar companies have proposed a number of measures over the last few years in an attempt to reduce output and set a price floor. Their efforts, however, have been unable to curb excess capacity or deliver a meaningful recovery in prices.

Against that backdrop, executives are now focusing increasingly on energy storage as a potential escape route. The traditional concept of a standalone solar manufacturer will gradually fade as companies seek to capture growing demand for batteries, particularly from power-hungry data centers, said Zhu.

Longi Green Energy Technology Co., China’s largest solar-panel maker by market value, entered the storage business only late last year. The company is now aiming for a storage division that will grow to the same scale as its solar business within about five years.

Still, the rush into batteries has prompted concerns that the industry could repeat the mistakes that led to today’s solar glut. Several executives at the conference cautioned that investment is already pouring into energy storage at a pace that risks creating another oversupplied market. The government has also delivered such warnings.

“All those who are involved in solar are now focusing on energy storage,” Shi Zhengrong, founder of Suntech Power Holdings Co., said during a panel discussion. “I don’t know whether this is a good thing or a bad thing. But looking at the current trend, it makes me feel a bit scared.”

Some executives are looking even further ahead. GCL’s Zhu pointed to space-based solar power as a potentially vast source of future demand.

While the concept remains largely theoretical, solar panels deployed in orbit could support about 200 gigawatts of demand from space-based data centers over the next decade, Dennis Ip, an analyst at Daiwa Capital Markets Hong Kong Ltd., wrote in a note earlier this year.

In a more speculative scenario, lunar artificial intelligence facilities could eventually create more than 10,000 gigawatts of demand — roughly equivalent to current global electricity consumption.

Thirteen founding members, including GCL, Trina Solar Co. and several research institutes, used the opening day of the conference to launch the Space Energy Development Alliance. But industry groups caution that such projections remain far removed from commercial reality. The China Photovoltaic Industry Association, the main solar lobby, has said that most space-solar technologies are still confined to laboratories or early-stage testing.

Key Data Points:

• Polysilicon prices in China resumed a decline this week, with a shift in market sentiment driven by high inventory pressure and changing supply expectations, according to a weekly note from the China Silicon Industry Association
  • Prices fell as much as 1.7% in the week through Wednesday, with the most expensive N-type material retreating to 34,700 yuan ($5,122) per ton
  • Output in June is expected to rise to 91,000 tons, while demand from downstream wafer producers is estimated at 87,000 tons
• Wafer prices were steady in the week through Thursday, with the most expensive N-type G12 product priced at 1.17 yuan per slice
• Solar cell prices were at 0.31-0.33 yuan per watt and module prices at 0.71-0.75 yuan per watt, both unchanged from a week earlier

What Happened This Week:

• Jinko Solar Co. said it signed 10 agreements during the SNEC PV+ conference to provide modules to China, the Philippines, Bangladesh and Pakistan
  • Co. didn’t provide details of the total volume of those orders

©2026 Bloomberg L.P.

The Ministry of Economy, Trade and Industry proposed replacing as many as five atomic power plants by the 2040s and up to a further nine the following decade, in a revised draft of its action guideline on nuclear energy policy that was sent to an internal committee on Friday.

Japan has been slowly re-embracing atomic energy after shutting down all of its plants following the Fukushima disaster in 2011. It’s now restarted around half of its about 30 commercially available reactors, with the country’s renewed enthusiasm being driven by the artificial intelligence boom boosting electricity consumption, as well as reducing emissions.

The environment surrounding nuclear energy has changed significantly, driven by expectations of increased electricity demand due to a ramp up in the digital and green transformations, the ministry said in a document on the proposal. A growing emphasis on energy security amid rising geopolitical risks including those in the Middle East also puts additional importance on a stable energy supply, it said. 

Japan will need to replace two to five reactors in order to secure around 2.2 gigawatts to 5.5 gigawatts of nuclear power capacity by the 2040s, the ministry said. Some 11 to 14 reactors will be needed by the 2050s, to achieve 12.7 gigawatts to 16 gigawatts of capacity in total, it said.

©2026 Bloomberg L.P.

State-owned Pakistan LNG Ltd. bought a cargo for June 6-7 delivery from BP Plc via a tender that closed on Thursday, according to traders with knowledge of the matter. The South Asian country was forced to purchase it because a planned shipment from Qatar was canceled due to heightened tensions around the strait, the traders said.

The cargo was bought at $19.1337 per million British thermal units, which makes it the priciest LNG purchase for the South Asian country since 2022, according to traders.

Pakistan is among the hardest-hit by the conflict in the Middle East, as about a fifth of global LNG supply remains stuck behind the narrow waterway blockaded by Iran and the US. Pakistan depends on Qatar for nearly all its LNG and has seen rolling blackouts due to severe fuel shortages since the war began in late February. 

Peace talks between Iran and the US have stalled and this week saw the worst flare-up in violence across the region since a fragile ceasefire went into effect in early April, dampening optimism that the Strait of Hormuz can be reopened any time soon.

Islamabad negotiated with Iran for the passage of three Qatari LNG shipments through Hormuz over the last month, with the latest arriving in late May. While that’s helped ease the country’s gas shortfall, it is still receiving far fewer shipments than normal, forcing the country to dip into the expensive spot market.

Pakistan purchased its first spot shipment in about two years in April.

©2026 Bloomberg L.P.

The policy expected to debut this month would increase the offtake price of compressed biogas, or CBG, and offer financial benefits to companies for spending on new projects, according to people familiar with the matter. The goal is to increase the number of operational CBG plants over the next several years to about 700 from roughly 200 currently, said the people, who did not want to be identified discussing confidential details.

Compressed biogas is methane produced from organic waste including paddy straw, cattle dung, food and household leftovers. Policymakers view it as a carbon-negative fuel because it captures emissions that would otherwise go into the atmosphere and creates a substitute for fossil fuels. State-owned oil marketing companies and gas utilities currently pay gas producers around 72 rupees ($0.76) to 74 rupees a kilogram for CBG, which is blended with other natural gas that is supplied to households and automobiles via pipelines.

India has been trying to ramp up biogas production for much of the past decade, but output has fallen far short of its earlier goals. The latest effort has taken on more urgency amid the Iran conflict, which has exposed the South Asian nation’s vulnerability to global price swings and supply disruptions. India currently imports about half its gas needs, and much of that comes via the Strait of Hormuz, which has been largely closed for months. New Delhi is seeking to make alternatives to imported oil and natural gas more commercially viable, while trying to meet climate goals and tackle chronic agricultural pollution. 

Dubbed , which means “complete” or “perfect” in Hindi, the new program will be implemented by India’s Ministry of Petroleum and Natural Gas, the people familiar said. The ministry didn’t immediately reply to an email seeking comment.

Back in 2018, Modi’s administration had set an ambitious target of 5,000 biogas plants nationwide by March 2024, with a goal of producing 54 million cubic meters of gas daily, or roughly half of the country’s demand at the time. 

In February this year, India’s oil minister said in a post on X that the country’s 134 CBG plants were producing about 930 tons of biogas per day, which would be less than 1% of its consumption needs. India’s government is aiming to increase the proportion of biogas blended with other natural gas to 5% of total consumption by the fiscal year ending March 2029.

Air pollution

The government incentives are expected to support projects using agricultural residue and food waste, including material sourced through agencies such as the Food Corporation of India, the people said.

Some of India’s top conglomerates have invested in biogas projects, including Reliance Industries Ltd., which pledged last year to bring online 55 compressed biogas plants with a cumulative capacity of 400,000 tons a year. It is targeting 500 plants by 2030. 

Japan’s Suzuki Motor Corp., parent of India’s largest car maker Maruti Suzuki, opened a pilot plant in 2024, followed by its first full-scale biogas plant in India in December and a second a month later. It plans to build a total of five biogas facilities fed by cow dung in the state of Gujarat.

The program also is intended to address one of India’s most persistent environmental challenges: the seasonal burning of crop residue across its northern states. Farmers often burn paddy straw after harvest to quickly clear fields for the next planting season. That has contributed to severe air pollution that regularly blankets New Delhi and surrounding regions.

India previously attempted to increase investment in the sector through policies such as a Sustainable Alternative Towards Affordable Transportation initiative to encourage biogas plant development. Another program to convert farm waste into fertilizer and biogas is called the Galvanizing Organic Bio-Agro Resources Dhan. Those efforts helped establish an initial pipeline of projects but fell short of official ambitions amid financing challenges, feedstock constraints and concerns about commercial viability.

New Delhi’s latest policy effort is expected to improve project economics and attract private investment into the sector, one of the people familiar said. The increased price support is particularly significant because developers have long argued that existing returns were insufficient to justify large-scale investment in biogas infrastructure, he added.

©2026 Bloomberg L.P.

On Thursday, US President Donald Trump said that his government will spend nearly $700 million to finance coal plants in the country and increase exports. 

To support his decision, President Trump invoked the Defense Production Act, which allows the president to expand production in industries crucial to the country’s national security.

The announcement coincides with the effective blockage of the Strait of Hormuz since early March and rising energy prices in the US as a result of the war with Iran.

Growing coal exports

In his announcement, President Trump said the US will set aside $500 million to establish a new export centre in California and save 14 existing coal plants across Kentucky, North Carolina, Indiana, Tennessee, Arkansas, Arizona, Oklahoma, North Dakota, Wisconsin and West Virginia.

The first new coal plants in the US since 2013 will be constructed in Alaska and West Virginia using the remaining $200 million.

Earlier this year, the US also ordered coal plants to keep operating past their retirement age, a significant development for the North American industry.

Europe’s coal plants to remain open

Across the pond in Europe, Italy said it will postpone the permanent shutdown of its coal-fired power plants until 2038, 13 years later than the original deadline.

German Chancellor Friedrich Merz has also said that the country may have to delay coal plant closures: “We may even have to keep existing coal-fired power stations connected to the grid for longer, should the energy crisis continue, and a shortage actually arise.”

While the Middle East conflict has accelerated the redeployment of coal, its resurgence can also be partly attributed to the COVID-19 pandemic and the heightened Russia-Ukraine conflict in 2022.

These events exposed Europe and the rest of the world to supply chain vulnerabilities and prompted countries to reassess their energy strategies. Data from the IEA shows that global coal consumption only grew after 2020, after declining in previous years.

India and China: the coal giants

Any analysis of the coal demand cannot be complete without discussing both India and China. According to the IEA's Global Energy Review 2024, China's coal demand increased by 1.2%, setting a new record.

The nation now uses around 40% more coal than the rest of the world, mostly for electricity generation. China's power plants use more than one-third of the world's coal.

Meanwhile, demand in India, the second-biggest coal user in the world, reached an all-time high of 5.5% in 2024. In 2024, the production of coal power increased by 5% in tandem with the rise in the demand for electricity.

In 2023, Southeast Asia emerged as the world's third-largest coal-consuming region. In 2024, coal consumption increased by over 8%, thanks to Indonesia, Vietnam, and the Philippines.

The primary development driver in Indonesia was its use in the metallurgical industry. Coal power generation was the primary engine in Vietnam and the Philippines.

Coal in the world of AI

A key factor in the resurgence of coal has been the spiralling demand for electricity, with AI and data centres being major contributing factors. Research from Lawrence Berkeley National Laboratory shows that by 2028, more than half of the electricity used by data centres will be for AI.

According to the IEA, data centre electricity use reached 415 terawatt-hours (TWh) in 2024, or almost 1.5% of the world's total power consumption, marking a trend where usage has grown at 12% per year over the last five years. 

Instead, it became home. That happens here more often than you realise — Calgary has a way of adopting you.

I’ve spent most of those 14 years close to one event, the Global Energy Show, and I’ve come to think of it as something more than a conference. It is, in the truest sense, a gathering of believers.

The show is 58 years old and began with an idea from Jim Gray. A pioneer of the Canadian oil and gas industry, he wanted to put Alberta’s energy sector on a stage at a time when much of the world had never heard of it.

There was a long stretch when the case for Canadian energy was compelling on paper and frustrating in practice.

The geology and engineering was world-class. The people were world-class. And still the infrastructure stalled.

Pipelines waited. Approvals didn’t come. Capital, which is patient with almost nothing, went looking for certainty elsewhere. In those years, the Global Energy Show got smaller. The conference rooms were quieter.

But the show never went dark.

Through those difficult years, the delegates kept coming. The exhibitors kept booking. Engineers, students, suppliers, financiers, indigenous leaders and families with generations of careers in industry kept showing up. They are a community, and they refused to quit on Canadian energy.

My colleagues and I have always understood our role. We don’t own this event. We steward it. It belongs to that community, and to this city.

What a difference a year makes.

Canada has loaded its first LNG cargo from the Pacific coast. More than $100 billion in major projects are formally in motion. A country that spent a decade arguing about pipelines and infrastructure is almost unrecognisably united around the idea that energy is not a liability to be managed but a foundation of our sovereignty, prosperity and our standing in the world. We are comfortable saying the words out loud: Canada can be an energy superpower.

I’ll say what a lot of people in this city are feeling but are too gracious to say. The believers were right. The community that kept the lights on at the Global Energy Show through the lean years were not stubborn, they were early.

And now the world is coming to Calgary to catch up.

The Global Energy Show brings tens of thousands of attendees, hundreds of exhibitors, and delegates from more than 100 countries. This year alone, it’s expected to bring an estimated $70 million in economic activity to Calgary, fill our hotels and restaurants, and support tens of thousands of jobs across the city I now call home.

But the numbers are not the point, it’s what they represent — a city that was counted out, but did not count itself out, and is now the place the world arrives to do business.

This is a responsibility, and not a small one. The world needs what Canada has — reliable, responsibly produced energy from a country it can trust. Calgary is where Canada meets that world.

So, whether you are a student wondering whether this industry still has a future, an engineer who has spent 20 years in the field or a visitor flying in from Europe, Africa, Asia or anywhere else, Calgary is ready for you. We have been waiting for this for a long time.

• This article was first published in Calgary Herald ahead of Global Energy Show Canada 2026, taking place from June 9-11 at BMO Centre, Calgary. Book your delegate access here: https://www.globalenergyshow.com/register/

The company’s shares closed at $33.30 on Thursday, compared to the initial public offering price of $27 each. The trading gave the Munich-based company a market value of about $25.5 billion, based on the outstanding shares listed in its filings.

The offering consisted of 90 million shares sold by private equity firm Advent and the Abu Dhabi Investment Authority, up from the 75 million that were marketed for $24 to $27 each.

Innio sells engines under the brands Jenbacher and Waukesha and offers an AI-powered software platform for power plants called Myplant, according to its website. The company has production hubs in Austria, Canada and the US, its filings show.

The company’s five largest customers accounted for about 39% of its revenue in the first three months of 2026. Innio reported a net loss of $9 million on revenue of $668.6 million in the first quarter compared to net income of $35 million on revenue of $494 million in the same period the year before.

Innio is joining several other industrial firms going public this year, tapping interest from investors searching for companies that benefit from the artificial intelligence boom. 

In April, Madison Air Solutions Corp., a ventilation and filtration systems firm, raised $2.57 billion in the biggest US industrial-sector IPO since 1999, data compiled by Bloomberg show. A February listing by fellow power equipment maker Forgent Power Solutions Inc. raised $1.74 billion.

Advent bought Innio, which was previously General Electric Co.’s distributed power business, for $3.25 billion in 2018.

ADIA agreed to acquire a stake in the company in 2023, with Advent remaining the majority owner, according to a statement at the time. After the offering, an entity backed by Advent and ADIA was set to control 90% of Innio, according to a filing. Advent indirectly controls 54% of the vehicle and ADIA has about 45%.

Goldman Sachs Group Inc., JPMorgan Chase & Co. and Morgan Stanley worked on on the IPO. The shares trade on the Nasdaq Global Select Market under the symbol INIO.

(Updates shares in first two paragraphs.)

©2026 Bloomberg L.P.

The power sector has moved from years of flat demand into a new growth cycle, with AI emerging as one of the clearest drivers, Freiman, who is also head of North American infrastructure at KKR, said during the Sohn Montreal investment conference on Thursday.

Publicly traded power producers such as Vistra Corp., Constellation Energy Corp., NRG Energy Inc. and Talen Energy Corp. have already benefited from owning merchant generation in a market where electricity demand and prices are rising, he said on panel with executives from Blackstone Inc., Caisse de Depot et Placement du Quebec and PSP Investments.

“It’s become one of the clearer ways to express an AI bet on infrastructure,” Freiman said. Investors do not need to pick the winning AI model or semiconductor company, he added: “They’re going to need more power.”

The next phase, however, will be more capital intensive. Freiman said new gas-fired plants that once cost about $1,000 per kilowatt can now cost closer to $3,000 per kilowatt, making it unlikely that developers will build without long-term contracts. That shift is expected to pull more activity into private markets, where large infrastructure investors can finance projects backed by hyperscalers and other major customers.

“If you look at industries going through an inflection where there’s just a massive need for capital, it’s really hard to do that in public markets,” he said.

Unlike previous power booms, however, investors are showing little appetite for speculative construction. Robert Horn, senior managing director and global head of infrastructure at Blackstone Credit and Insurance said most new gas-fired projects are being backed by long-term contracts with utilities, industrial customers and technology giants such as Amazon.com Inc., Microsoft Corp., Alphabet Inc.’s Google and Meta Platforms Inc., providing predictable revenue before construction begins. 

That marks a sharp departure from the merchant power cycle of the early 2000s, when developers built plants in anticipation of demand and were left exposed when electricity prices fell. The shift has made the sector particularly attractive to private-credit providers and infrastructure investors, who are increasingly willing to finance projects supported by some of the strongest corporate balance sheets in the world.

The panelists also pointed to nuclear power as a likely long-term winner, though not an easy one for private capital. Freiman said there “will be a nuclear renaissance at some point,” but the early wave will probably need to be financed by the US government or hyperscalers, whose balance sheets are large enough to absorb the risks. Recent nuclear projects have suffered from major delays and cost overruns, making investors cautious, he added.

©2026 Bloomberg L.P.

In the latest sign of the growing pushback against the AI buildout, venture capitalist Kevin O’Leary of fame pledged to cut the 40,000-acre Stratos development in half. Most of the remaining area will be left as open space, O’Leary wrote in a letter to Utah Senate President J. Stuart Adams.

With those changes, the plan would be in line with calls for a 75% reduction in the overall size of the project, he added in the letter dated Thursday. Still, O’Leary said many of the environmental concerns had been overstated.

“Much of the alarm surrounding this project has been based on incorrect assumptions and facts about land use, water use, heat dispersion, air quality, and project timeline that does not reflect reality,” wrote O’Leary, chairman of O’Leary Digital. The project “has not broken ground, has not received permits, and the development plan is still being engineered and refined.”

The nine-gigawatt Stratos project in the northwest corner of the state has triggered raucous protests and even death threats against elected officials over environmental concerns including water usage in the Great Salt Lake area. 

O’Leary Digital didn’t immediately respond to a request for comment. It wasn’t immediately clear if the overall nine-gigawatt capacity of the project will change.

The dispute is the latest example of how the surge in data centers to power artificial intelligence is triggering community opposition. Concerns range from soaring power prices to a loss of jobs due to AI, as well as environmental impacts. 

Last month, a small Texas county outside Dallas approved a one-year moratorium on new data center and energy storage developments.

In response O’Leary’s letter, Adams welcomed the decrease in the project’s size. He reiterated that the project was still in its earliest stages and would have to conform to Utah regulations and protect nearby water resources.

“With responsible water use, transparency and input from the people of Utah, we will show the nation how to build it right,” Adams said in a statement. “There must be written commitments in place, and the proposal must undergo a full permitting and environmental review process, just like any other development project in Utah.”

©2026 Bloomberg L.P.

European Commission President Ursula von der Leyen pledged in March the EU will come up with a new instrument based on 400 million existing allowances in the Emissions Trading System to finance decarbonization projects. The commission plans to spread out sales of permits from the so-called ETS Investment Booster to prevent sudden price slumps during the process, according to people with knowledge of the matter.

EU climate and energy policies are at the top of the bloc’s political agenda as fallout from the Iran war compounds fears that the region is losing its competitive edge against China and the US. The commission is seeking to balance its ambitious emissions-reduction goals with concerns among some governments and heavy industry that carbon costs are inflating already high energy prices. 

Benchmark carbon contracts fell 2% to 77.01 euros per ton on Thursday. Brussels estimates that the cost of carbon accounts for around 11% of electricity prices on average, with countries relying on clean energy facing a smaller burden. Countries like Poland, where the share of carbon costs in the power bill is as high as 24%, have led the push for a new EU instrument to alleviate the financial strain of the energy transition.

The details of the new ETS-based instrument will be outlined when the EU unveils a review of its flagship cap-and-trade emissions program on July 15. The allowances in the booster will come from a reserve for new entrants in the ETS and from an existing buffer of free permits that can be handed to companies as support of low-carbon investments, said the people, who asked not to be identified discussing a confidential matter.

The commission was not immediately available for comment.

The new tool is set to become part of the EU Industrial Decarbonization Bank, a broader instrument that is expected to secure 100 billion euro in funding for the energy transition, according to the people. 

Once unveiled by the commission, the ETS review will be discussed by the European Parliament and member states in the EU Council. Each of the institutions has the right to propose amendments in a legislative process that typically takes as long as two years. 

One option under consideration by the commission is to propose fast-tracking a part of the reform to bring forward permit sales under the booster, helping to accelerate the industrial shift to cleaner energy.

©2026 Bloomberg L.P.

The nation’s largest power producer aims to add as much as 2,000 megawatts of data center capacity during the period to meet rising demand for AI and cloud-computing services, Chief Financial Officer Yupapin Wangviwat said during a video conference with investors on Thursday. The company and its partners currently operate facilities with a combined capacity of about 200 megawatts.

“We see AI and cloud computing as major growth opportunities for our company,” she said. “Our strong footprint and expertise in the power business give us a significant advantage as we expand into these areas.”

The company’s shares jumped as much as 5.8% to a record on Thursday, set to push their gain for the year above 61%.

The move reflects a growing race across Southeast Asia to build the computing power needed for AI. Technology companies are pouring billions of dollars into data centers as they seek more capacity for AI tools and online services, creating new opportunities for energy and infrastructure providers.

After consolidating his power and telecommunications businesses into Gulf Development last year, Sarath — whose net worth stands at $18.3 billion, according to Bloomberg Billionaires Index — has been steering the company into new areas including digital infrastructure, virtual banking and AI-related services as it looks for new sources of growth.

Gulf Development has been strengthening its presence in the sector through partnerships with companies including Microsoft Corp. and Singapore Telecommunications Ltd., as demand for computing capacity accelerates across the region. It also entered into an agreement early this year with Alphabet Inc.’s Google to jointly explore business opportunities. 

The Bangkok-based company expects to fund the expansion through operating cash flow, bond sales and bank borrowings, according to Yupapin. It is in talks with lenders for loans of between $400 million and $600 million, and plans to issue about 20 billion baht of bonds in September. Gulf Development is also considering its first foreign-currency debt sale.

©2026 Bloomberg L.P.

The firm will help customers set up and run complex renewable energy systems, assisting with project design, construction and maintenance through their entire life cycle, Suzlon’s Vice Chairman Girish Tanti said in an interview. 

The pivot comes at a crucial time for the industry, according to Tanti. The ongoing conflict in the Middle East is adding financial pressure on India, a large importer of fuels whose circulation depends on the region. Strengthening energy security while decarbonizing the economy requires clean electricity to be available when needed, not just when the weather allows, and storage is considered key to the task.

“If renewables have to become the main source of our supplies, they have to be stable and dispatchable,” Tanti said. 

The Pune-headquartered firm aims to scale the portfolio of managed energy assets fourfold to 70 gigawatts in five years, it said in a statement on Wednesday. The company added it will move toward a full-stack solutions provider and establish a battery energy storage manufacturing facility by next year.

Suzlon has its own wind turbine manufacturing plants and it plans to source solar equipment in the country, Tanti said. Most wind sites can accommodate solar and battery systems and the company is negotiating with their operators to re-purpose them. 

Besides integrated renewable energy projects, wind power’s ability to meet India’s demand peaks when the sun is out also makes it an attractive bet. As a result, the country added a record 6.3 gigawatts of such installations in 2025 and additions could rise beyond 8 gigawatts in 2026, Tanti said.

©2026 Bloomberg L.P.

Brent traded around $97 a barrel, while West Texas Intermediate was near $96 after rising almost 10% over the first three sessions of the week. The agreement hinges on “a complete cessation” of fire from Iran-backed Hezbollah, according to a joint statement from Israel, Lebanon and the US.

Washington and Tehran have sketched out a framework to extend their truce by two months and reopen the Strait of Hormuz, but negotiations are stalling and sporadic fighting has resumed. Iran warned it could target sites inside Israel if attacks on Beirut continue, according to the semi-official Tasnim news agency, which cited the country’s foreign minister. He also said little tangible progress has been made in the talks.

Oil prices have recovered from last week’s decline as renewed clashes damped hopes for a sustained ceasefire and a reopening of the key shipping route. At the same time, global supply buffers are shrinking. US figures on Wednesday showed crude inventories at Cushing, Oklahoma — the delivery hub for WTI — fell for a sixth straight week, nearing minimum operating levels.

Even if an Israel-Lebanon ceasefire caps some near-term price gains, risks remain elevated while the strait stays effectively closed. Brent could climb as high as $130 a barrel in the fourth quarter as inventories tighten, said Robert Rennie, head of commodity research at Westpac Banking Corp.

“The market is asleep at the wheel, even as we drive rapidly toward aggressive tightening in crude and product markets,” Rennie said.

President Donald Trump said the Strait of Hormuz would reopen “immediately” if Iran signs a memorandum of understanding to halt hostilities, adding that some areas in the waterway would need to be cleared of mines. He downplayed the threat those pose to commercial shipping.

The strait remains the market’s central focus. Roughly a fifth of global crude supply typically passed through the chokepoint prior to the war, and its near-closure has pushed energy prices higher, raising concerns about a spike in inflation and slowdown in economic growth.

The conflict in the Middle East has pushed observable oil-product inventories below a five-year average, and crude prices could “skew higher” as US-Iran talks falter, Citigroup Inc. analysts including Eric Lee said in a note.

Separately, the Republican-led House voted to halt the US war with Iran, underscoring growing concern within Trump’s party months ahead of midterm elections. The measure is unlikely to immediately affect military operations, as the Senate would still have to pass the resolution, and provisions in the 1973 War Powers Act that the House invoked are legally controversial anyway.

©2026 Bloomberg L.P.

The EU’s revised Energy Efficiency Directive and minimum energy efficiency standards for data centres are in line with the bloc’s 2030 target of reducing greenhouse gas emissions by at least 55% compared to 1990, it said in a statement. The European Commission said it would develop minimum ⁠performance standards for both new and existing data centres, with a “needs assessment” ​due by 2027, Reuters reported.

The EU is ​also working on ⁠a sustainability label for data centres, covering criteria including water use and clean energy supply, which large facilities would have to make public, it said. Officials told Reuters the Commission ​is ⁠still debating issues including how to assess data centres powered by nuclear energy.

The new EU rules imply strengthening incentives for data centres to improve energy efficiency and sustainability, and improving transparency and comparability by building on the reporting and rating framework under the Energy Efficiency Directive so that performance standards can be defined and enforced consistently across EU countries, the Commission said.

“If not ​tackled at EU level now, these challenges could grow considerably and become harder to ‌solve in ⁠the coming years, as the energy consumption of the sector is expected to increase further,” the Commission said.

The move comes amid projections that EU data centre capacity will more than double to reach 28 gigawatts by 2030 from 12 GW ​in 2025. That expansion will lift their share of EU electricity consumption ​beyond the current 2.5%, according to Reuters.

“Energy efficiency is a central pillar of the EU’s energy and climate framework, as well as being a key policy for delivering energy savings, improving affordability, and strengthening the competitiveness and resilience of the European economy on its path to climate neutrality,” the Commission said in a statement.

Data centres are expected to drive 20% of the growth in electricity demand in advanced economies by 2030, according to the International Energy ​Agency.

The Commission said it is also developing a post-2030 energy efficiency framework to help shape EU energy efficiency rules for the decade ahead, which is scheduled for publication later this year.

According to Reuters, the plans are part of a broader ⁠EU tech ​package aimed at boosting domestic cloud and ​AI capacity and reducing reliance on Big Tech. Other measures include using generative AI to speed up permitting for new energy projects ​and funding AI tools to help manage Europe's power grid.

Oritsemeyiwa Eyesan, Chief Executive of the Nigerian Upstream Petroleum Regulatory Commission (NUPRC), said the licensing round will begin after the completion of this year’s commercial bid process. 

Eyesan added that Nigeria is already seeing a rise in oil investments as production increases. 

Licensing rounds are key to bringing new exploration and developments to the market, and Nigeria is keen to lure fresh investments and restore investor confidence following years of regulatory uncertainty. 

“So, we are in the process of finalising the 2026 launch, which will happen latest by the third quarter,” Eyesan said, adding that this is the “make or break point and we want to make sure we make it.”

An attempt at transparency 

Last year, Nigeria introduced consequential amendments to its Petroleum Industry Act, which aim to reduce bureaucratic delays and accelerate investments across the oil and gas chain. 

If the amended bill passes, the formal authority of Nigeria’s oil and gas sector would transfer to NUPRC and the Nigerian Midstream and Downstream Petroleum Regulatory Authority (NMDPRA), changing hands from NNPC Limited. 

This means that regulatory requirements are now “integrated operations” where oversight will be coordinated for shared upstream-midstream operations. 

Approvals for contracts, financing, and dispute resolutions could become more efficient, experts have said. For oil and gas companies operating in the region, this could mean faster approval cycles, more predictable schedules, and fewer contract bottlenecks. 

This also means better cooperation between regulators, which could translate into fewer and more efficient steps for oil and gas companies. 

Following the proposed 2025 amendments, Nigeria has also reduced costs associated with licensing rounds and opened them up to independent authorities to increase transparency. 

Investors prepared for changes

Canada’s Meren Energy, which has invested heavily in Nigerian oil, has welcomed the licensing round. The company’s Group CEO, Dr Oliver Quinn, said that Nigeria's new reforms have “inspired the company to increase its investments” in the West African state.

“We have operated in Agbami, Akpo, and Egina world-class fields. I think till date, in 20 years, about $11b in capital from our side has gone into these assets, and about $4b has gone to tax and royalties,” he added. 

Nigeria’s commercial bid will conclude ahead of the commencement of NOG Energy Week. 

Taking place from 5-9 July at the Bola Ahmed Tinubu International Conference Centre in Abuja, the exhibition and conference will highlight the importance of Nigeria’s upstream performance as fundamental to national energy security, while looking at ways to drive investment to increase energy production. 

Strategic panel sessions will aim to answer key questions about this year's licensing round. They will examine the role of the 2026 bids in unlocking new capital, how they will accelerate exploration, how the new policies and regulations can strengthen investments, and how market conditions can enhance investor confidence. 

Not merely from traders or geopolitical commentators, but from multilateral agencies, trading houses, and global institutions whose job is to understand physical markets and economic risk.

Last week, the heads of the International Energy Agency, International Monetary Fund, World Bank and World Trade Organization issued an unusually stark joint warning following a high-level coordination meeting. Global oil inventories, they said, are being drawn down at a rapid pace in response to the supply shock triggered by the closure of the Strait of Hormuz. If shipping flows fail to normalise, continued depletion ahead of peak northern hemisphere summer demand would pose rising risks to fuel security, market conditions, and broader economic resilience, they said.

The IEA this week sharpened that message further. Toril Bosoni, head of its oil markets division, warned that commercial inventories could fall towards critical or historic lows if current draws continue. Even under a best-case diplomatic scenario, she cautioned, reopening Hormuz and restoring normal flows could take six to eight months. Emergency stock releases are merely a temporary stopgap and cannot resolve supply losses of this scale, Bosoni said, implying that any lasting adjustment would ultimately have to come from the demand side.

The private sector is sounding similar alarms.

Tom Baker, Vitol’s managing director for Bahrain, warned that the market may be underpricing the risks from the Iran war and Hormuz disruption. Crude supply may eventually recover, he argued, but refined products could remain structurally tight for the rest of the year. His most telling observation may have been that the real stress point arrives when buyers need physical barrels and “the physical molecules just aren’t there to buy.”

Goldman Sachs has shifted the spotlight to refined products, warning of a potential diesel squeeze in the US by August as refiners tilt yields towards jet fuel during the summer travel season. Even if crude balances stabilise, product markets may not.

Global inventories are approaching “unheard of” lows, ExxonMobil Senior Vice President Neil Chapman warned recently. Once inventories approach operational minimums, crude could spike towards $150-160/barrel, he said.

The common thread is difficult to ignore. This is no longer merely a story about lost supply. It is a story about shrinking buffers and a market running down its last line of defence.

Commercial as well as strategic reserves are being depleted at pace. Product balances are tightening. Yet futures markets continue to swing between alarm and complacency, still highly responsive to each round of “deal imminent” rhetoric emerging from Washington and Tehran.

Yet the louder the warnings grow, the more puzzling the muted policy response becomes.

Who exactly are these warnings directed towards?

Market participants, certainly. Refiners, importers, shipping companies, and industrial consumers need to hear them and adjust procurement strategies, supply chains, and contingency plans accordingly. For many, the menu of workable options is already narrowing, and the cost of waiting is rising.

Traders, too, should pay attention. Whether they will is another matter. The current crisis has curiously seen markets remain attached to narratives even though fundamentals are moving in another direction. At least one major trading house now openly argues that oil is underpriced relative to the physical risks confronting the market.

But perhaps the real audience is governments — especially those in net oil-importing countries.

And if so, why does the response still appear muted?

One possibility is denial — a head-in-the-sand syndrome born of disbelief that the global economy could genuinely be facing a supply shock of this magnitude and duration.

Another is miscalculation. Policymakers may believe strategic and commercial inventories can cushion the blow for longer than they actually can. That assumption deserves scrutiny. The current crisis has already crossed the threshold where running down inventories at an unprecedented pace looks less like a strategy and more like a desperate gamble.

A third possibility is that governments are allowing themselves to be guided by Washington’s persistent messaging that diplomacy is progressing and a deal is around the corner. Markets have repeatedly reacted to assertions that peace may break out any day and the Strait of Hormuz could soon reopen.

But even if such a deal materialises, there appears to be a dangerous leap in logic — namely, assuming that reopening Hormuz automatically means a rapid return to normal oil flows.

It does not.

Shipping patterns, insurance, security clearances, damaged infrastructure, and physical confidence take time to rebuild. Even Bosoni’s six-to-eight-month timeline for flows to normalise after the Strait reopens could prove optimistic. While a preliminary US-Iran deal would likely reopen Hormuz and launch talks on the more sensitive nuclear issues, that process could prove fraught and leave the recovery in Gulf flows vulnerable to renewed hostilities and interruptions if diplomacy falters.

Then there is politics.

Governments know the uncomfortable reality staring them in the face: if supply remains impaired and inventories keep falling, the only meaningful balancing mechanism left may be higher end-user prices and lower consumption.

That is rarely an attractive political proposition.

Asking citizens and industries to conserve fuel, curb discretionary travel or absorb higher energy costs is politically painful. Leaders understandably prefer to wait for better options to emerge.

But waiting could backfire.

The world is in uncharted waters. A supply disruption of roughly 15 million barrels per day — and one lasting months rather than days — has no precedent in living memory.

Yet the absence of a playbook is a poor excuse for failing to plan.

If Hormuz remains shut for weeks longer, governments and markets alike may have to confront an increasingly unavoidable truth. Demand will have to contract to match lost supply.

The only remaining question is whether that adjustment happens through deliberate and realistic planning and transparent policy, or through panic, shortages, and price spikes forcing the outcome anyway.