The fuel in question is red-dyed diesel, which is used in agriculture and construction, among other industries. Also called off-road diesel, the fuel is literally dyed red to distinguish it from the diesel sold for broad use. The red-dyed fuel is not subject to the federal excise duty and, as such, is cheaper than its broad-use version.

Diesel prices have emerged as a point of acute pain for Americans, hitting record highs earlier this month as the war between the United States and Israel with Iran entered its seventh month with no prospect of a swift resolution. As oil and fuel exports out of the Persian Gulf remain constrained, U.S. refiners ramped up processing rates to fill as much of the resulting supply gap as possible. Exports of both crude oil and fuels surged, especially to Europe, which lacks sufficient local refining capacity. The surge in exports also contributed to the fuel price inflation at home – and the recent rush by the federal government to bring prices down.

President Trump has repeatedly claimed that once the war is over (which he says will be soon), prices will go back down. However, unlike in the first weeks of the war, claims are not enough to bring prices down, so diesel fuel earlier this month topped $6.50 per gallon before retreating to $6.45 per gallon this week amid talk about a possible diesel export ban.

President Trump has signaled his support for a ban, while Energy Secretary Chris Wright has argued that ultimately, a ban would have the opposite of the intended effect. Analysts agree: if exports of diesel fuel are suspended for 90 days, per the proposal, refiners would first have to stock up their available volumes, and then they would need to reduce their run rates once storage space runs out. The run rate cuts would hit the supply of gasoline, leading to higher prices for that fuel.

The situation, in other words, is complicated with no easy fix available. Cutting excise duties on fuels is a go-to measure that governments deploy in times of fuel price trouble. All European countries already have some version of that in effect to help drivers weather the crisis. Asian nations have also cut excise duties to cushion the fuel crisis blow.

Reuters reports that the federal highway tax burden for broad-use diesel fuel stands at $0.244 per gallon. Red-dyed diesel used for tractors, construction vehicles, forklifts, diesel generators, and heating systems is exempt from these taxes. In other words, broadening the availability of red-dyed diesel would, in theory, reduce prices by nearly $0.244 per gallon. Not all agree this would make much sense.

“I can’t think that this would have any impact at all,” GasBuddy’s head of petroleum analysis Patrick De Haan said, as quoted by Reuters. “It’s simply diesel with red dye added that’s not taxed. It does nothing to improve supply or impact price.”

Fundamentally, the United States is producing more diesel fuel than it is using. At 5.1 million barrels daily, output exceeds an average daily consumption rate of some 3.6 million barrels. Exports average 1.2 million barrels. However, due to the global nature of the diesel market, a supply squeeze in the Middle East sends a ripple effect across the globe, hitting U.S. diesel prices despite production rates.

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The move is broadly seen as helping sales of gas-powered cars and trucks at the expense of electric vehicles.

The Alliance for Automotive Innovation called the rollback an “appropriate course correction” that aligns fuel economy standards with market realities and legal requirements. (Automotive News)

Environmental groups countered that the rollback gives automakers a break while US drivers continue to grapple with sharply higher fuel prices due to the war in Iran.

Per Reuters:

The Transportation Department said it was finalizing a fleetwide average of 34.9 miles per gallon (14.7 km per liter) by 2031, down from 50.4 miles per gallon (21.4 km per liter) under Democratic former President Joe Biden.

In 2024, the Biden administration finalized rules to push automakers to build more electric vehicles to meet rising fuel-efficiency standards. Biden increased required fuel efficiency for cars by 8% annually for model years 2024 and 2025, 10% for 2026 and 2% annually from 2027 to 2031.

The lower standards mean higher global carbon emissions, a slowdown in the worldwide shift to electric vehicles, and a strategic retreat by the US from the global clean-energy race.

The policy encourages the production of larger, less efficient gas-powered trucks and sports utility vehicles, keeping global oil demand high for decades.

It also ends a credit-trading system automakers used to comply with requirements, effective in model-year 2028, thus removing a major financial cushion for pure electric vehicle pioneers like Tesla and Rivian.

International car companies such as Toyota, Volkswagen and Hyundai can now sell more profitable gas vehicles in the US while keeping EV development focused elsewhere.

The Trump administration estimates technology costs will drop $60.6 billion through 2031, with Stellantis saving $6.6 billion, Ford $5.8 billion, Toyota $4.5 billion and Honda $4.1 billion, Automotive News reports.

While the US has finalized sharply lower standards, the European Union and China are moving in the opposite direction with strict, legally binding timelines.

Europe’s regulations require a 100% reduction in tailpipe emissions for new cars by 2035. This creates a legal phase-out of traditional internal combustion engines (ICE).

China approaches vehicle regulation from two sides: a strict fuel consumption standard for gas cars and an aggressive New Energy Vehicle (NEV) mandate.

China uses a “dual-credit” system that forces automakers to accumulate points by manufacturing a high percentage of EVs and plug-in hybrids. This strategy has allowed Chinese automakers to capture roughly 60% of global EV sales.

While the US is just measuring gas consumption, China implemented a law which regulates the efficiency of electric car batteries. This forces companies to build lighter, longer-range EVs rather than just larger batteries.

The bottom line? The US has essentially hit the brakes on forcing its auto industry toward electrification, giving domestic manufacturers breathing room to focus on highly profitable gas SUVs and trucks.

Meanwhile, Europe and China are continuing down a strict regulatory pipeline, forcing global automakers to build highly advanced electric drivetrains if they want to access the European and Asian markets.

Fuel economy or greenhouse gas (GHG) emission standards for new passenger vehicles currently exist in over 40 countries, covering more than 80% of new passenger vehicle sales worldwide.

The primary regulatory drivers include the United States, the European Union, China and Japan, which together represent the largest blocks of global fuel consumption and vehicle manufacturing.

Most of these national and regional policies rely on corporate-average fuel economy (CAFE) or fleet-average greenhouse gas tailpipe limits, scaling targets based on vehicle attributes like size or weight rather than imposing a flat standard across all classes.

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And now commodity analysts at Standard Chartered have hiked their oil price forecasts amid stalled diplomacy efforts and regional escalation beyond Iran and Hormuz.

StanChart has raised its average Brent crude forecast for 2026 to $92.00/bbl from its previous forecast at $85.50/bbl, while WTI crude is now expected to average $86.00/bbl, up from $80.25/bbl. StanChart has also hiked its 2027 oil price forecasts, and now sees Brent averaging $89.50/bbl from $77.50/bbl, while WTI crude rises to 89.50/bbl from $77.50/bbl.

According to StanChart, the global energy market is now confronting a more persistent deterioration in the Middle East security environment, with little prospect of a return to the pre-conflict status quo and no real pathway to a settlement visible yet. The conflict continues to spill over into a wider regional security problem, with the Houthi/Saudi escalation adding a second front and Saudi Arabia being drawn in deeper.

Source: Standard Chartered

StanChart notes that both Brent and WTI remain caught between structural tightness and policy risk. Supply buffers are extremely thin, which means that price moves are highly sensitive to further disruption. StanChart expects only a gradual and imperfect de-escalation process, even if US-Iran negotiations resume shortly, with periodic flare-ups in tension likely to keep a premium embedded in prices.

Meanwhile, the events of 2026 are accelerating a shift in the energy system from efficiency towards resilience, StanChart notes. For years, companies cut inventories, consolidated supply chains and prioritized efficiency over resilience. The analysts believe that approach is now reversing as governments, producers and consumers build larger inventories, maintain more spare capacity and diversify suppliers. That shift raises costs, but it also supports a higher long-term floor for oil prices. As a result, they expect oil markets to normalize more slowly, with elevated prices likely to persist into 2027 and beyond.

In the products markets, diesel prices have surged to an all-time high, with StanChart saying it has now moved from a market problem to a policy problem. The next few weeks could clarify how far the Trump administration is prepared to intervene in U.S. product markets as the midterm elections approach. Significant internal pressure for a U.S. diesel export ban remains, particularly from those battleground states where high diesel prices coincide with a key agricultural harvest season (Iowa, for instance). 

Trump has backed restrictions on diesel exports previously; however, many in his cabinet (including energy secretary Chris Wright), have warned that this could ultimately also lead to tightening both gasoline and jet fuel supply. This would, in turn, make both the global product problem worse and (after temporarily helping U.S. consumers), end up damaging Gulf Coast refining economics, potentially lowering crude runs.

StanChart notes that pressure to demonstrate action on domestic prices is leading the administration to consider less disruptive alternatives, including voluntary export reductions by refiners and broader use of tax-exempt dyed diesel.

In the natural gas markets, the EU Commissioner for Energy and Housing Dan Jørgensen recently urged member states’ energy ministers to both sustain stronger injections and consider measures to reduce gas and electricity demand, warning of a potential price crisis linked to supply risk. However, the urgency in Brussels is less evident in the market, with European natural gas futures falling to €69.30 per megawatt-hour on Tuesday, the lowest level in a month on weaker Chinese LNG demand.

According to StanChart, this push from the EU Commission is an attempt to prompt a stronger response and to bridge the disconnect in urgency between the state and market. The analysts note that existing flexibility to lower the storage target to 80% may ease near-term price pressure, but it does not fully remove Europe’s exposure in winter.

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While air attacks by both sides have subsided recently, ships in the key waterway continue to be targeted by Iran, which claims control over the strait despite US assertions that it remains open.

“In a region where we cannot sell oil, no one else will sell oil either; or if our security is not guaranteed, no infrastructure will remain safe,” Iran’s chief negotiator Mohammad Baqer Qalibaf said in a video broadcast by state TV on September 29.

The threat came on a day Iran was expecting an official response from US officials over a plan Tehran offered last week to reopen the strait, which before the war was the transit lane for around one-fifth of the world’s gas and oil supply.

US President Donald Trump has dismissed the plan, under which Tehran proposed reopening the strait and restarting nuclear talks in seven days, contingent on Washington lifting its naval blockade of ships heading to Iran, the removal of sanctions on oil sales, and the re-imposition of a regional cease-fire.

However, Trump also has said he expects more talks between US and Iranian negotiators this week.

As it awaits a potential official answer to its proposal, the powerful Islamic Revolutionary Guards Corps (IRGC) published a letter to American voters on September 29, where it blamed the United States for starting the war on February 28, while adding that the two countries could coexist if US policy changed.

The letter, aimed at US voters who Tehran said could change the course of the conflict, also claimed that more than 3,600 Iranians — mostly civilians, including 400 children — were killed during the war. The United States says it has lost 18 of its troops in the war.

The letter concedes that air strikes have destroyed part of Iran’s nuclear industry and a “limited” number of air defense sites. It also repeated Tehran’s assertion that its nuclear program was solely for civilian purposes.

RFE/RL has reached out to the US State Department for comment on the letter, but did not receive an immediate response.

US voters head to the polls in midterm elections on November 3. All 435 seats of the House of Representatives are being contested, as well as one-third of the Senate’s 100 seats.

By RFE/RL

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The EIA’s data release follows API’s figures that were released a day earlier, which reported that crude oil inventories had gained 1.019 million barrels in the period.

Crude futures were trading up at 10:22 a.m. in New York. Brent futures were trading at $103.34 per barrel—up $0.75 (+0.73%) on the day and up roughly $2 per barrel from this same time last week. WTI was also trading up on the day, by $1.38 per barrel (+1.54%) on Wednesday morning at $90.76, down about $1.25 per barrel since this time last week.

For total motor gasoline, the EIA reported that inventories decreased by 1.7 million barrels, after losing 1.7 million barrels in the week prior. The most recent figures showed that average daily gasoline production averaged 9.5 million barrels. For middle distillates, inventories decreased 2.3 million barrels, with production decreasing to an average of 5.0 million barrels daily. Distillate inventories are now 14% below the five-year average.

Total products supplied—a proxy for U.S. oil demand—averaged 20.8 million barrels per day over the last four weeks, up 2.1% compared to the same period last year. Gasoline demand averaged 8.7 million barrels per day over the last four weeks, with the distillate four-week average supplied at 3.8 million barrels—up 5.2% year over year.

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September data show particularly strong increases in southern Europe. Spain’s harmonized inflation rate jumped to 5.0%, up from 4.6% in August and its highest reading in several years. Spain’s statistics agency INE said rising prices for fuels and lubricants were among the main drivers. Spain’s domestic CPI rose 4.9%, while core inflation increased more modestly to 3.1%.

Italy is experiencing a similar energy shock. Headline inflation accelerated from 3.3% in August to 4.2% in September, according to preliminary data from Istat. Regulated energy prices surged 25.9% year-on-year, while non-regulated energy prices jumped 22.2%. By comparison, Italian core inflation remained much lower at just 1.7%.

The divergence between headline and underlying inflation highlights the extent to which Europe’s latest inflation problem remains an energy story.

Europe is particularly exposed to global energy shocks because of its dependence on imported oil and natural gas. The latest surge in crude and fuel prices resulting from the Middle East conflict therefore works its way relatively quickly through transportation, manufacturing and household energy costs.

Diesel has become an especially painful part of Europe’s latest energy shock. The region remains structurally dependent on imported middle distillates, leaving it exposed when global supplies tighten. Disruptions to Middle Eastern and Russian refining and trade flows have sent diesel crack spreads—the premium of diesel over crude—sharply higher, meaning European consumers are being hit by both elevated crude prices and unusually expensive refining margins. With replacement barrels increasingly competing for long-haul supply, higher freight costs are adding another layer to the price shock.

The situation inevitably recalls the energy crisis that followed Russia’s invasion of Ukraine. There is, however, an important difference so far: the latest energy shock has not produced comparable second-round inflationary effects across the broader economy.

Italy illustrates that divide particularly clearly. Energy prices rose 22.3% year-on-year in September, while core inflation was only 1.7%.

That distinction could determine what the ECB does next.

The central bank already raised its three key interest rates by 25 basis points on September 10, taking the deposit facility rate to 2.50%. The ECB explicitly cited inflationary pressure generated by the Middle East conflict and warned that inflation was likely to remain “well above target for an extended period.”

ECB staff currently expect headline inflation to average 3.0% in 2026, 2.5% in 2027 and 2.1% in 2028, compared with the central bank’s 2% medium-term target. But policymakers have also emphasized the uncertainty surrounding the duration of the energy shock and the extent to which it eventually spreads into underlying inflation.

That leaves Europe confronting an increasingly difficult trade-off.

Raise rates too aggressively and the ECB risks weakening an economy already absorbing sharply higher energy costs. Move too slowly, and policymakers risk allowing the oil shock to become embedded in wages, services and inflation expectations.

For now, Europe’s renewed inflation problem remains primarily an energy problem. The crucial question is whether it stays that way.

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Currently, Africa has around 441 million metric tons of annual cement production capacity in operation, good for 8% of the global total. However, the continent also has 43.3 million tons of annual capacity under construction, while African nations have announced plans for another 23 million tons, bringing total capacity to over 507 million tons, or 15% of the global total. 

Source: Reuters

Nigeria leads the pipeline for capacity under construction in the continent with 10 million tons currently being built, ranking second globally only to India. As Africa’s leading cement manufacturer, Dangote Cement Plc is executing a $1-billion pan-African expansion strategy through 2030 to reinforce its market dominance. Dangote is currently upgrading its export terminals in Lagos to boost shipments to West and Central African neighbors.

Similarly, BUA Cement is closing the gap with its competitors through a $1.05-billion investment as the country expands its footprint toward an 80-million-metric-ton national capacity target by 2030. Under an engineering agreement with China’s Sinoma CBMI, BUA is constructing three new cement plants with a capacity of 3 million tonnes per annum (mtpa) each, nearly doubling its total output capability to 20 million tons annually.

In neighboring Cameroon, Taiwan Cement Corporation (TCC), via its acquired subsidiary CIMPOR recently completed a 1.2 million-ton cement plant that cuts emissions by 40% using calcined clay and cocoa shells for fuel, while Heidelberg Materials is constructing the world’s largest flash calciner in Ghana.

Meanwhile, Kenya’s cement industry is experiencing a significant wave of consolidation and multi-billion shilling expansions, with the country focused on achieving clinker self-sufficiency. The Devki Group has committed $385 million to build Kitui County’s first cement and clinker facility. Located in Mwingi North, the plant sits directly on vast local limestone deposits, and is designed to produce 3 million tonnes of clinker annually. Devki is also planning a 1.2-million-tons/year clinker plant in Kajiado, while Cemtech Ltd is constructing a $348 million clinker plant in West Pokot.

Libya, Angola, Uganda, Mali and Mozambique also have lined up major cement construction roadmaps that are among the world’s most ambitious, while installed capacity in Sub-Saharan Africa is projected to double from 280 million metric tons to over 500 million metric tons.

Africa’s cement boom could also mark the beginning of a much larger increase in energy demand. 

Cement consumption typically rises early in the industrialization cycle as countries build housing, roads, ports and factories. Those projects then support the expansion of more energy-intensive industries, including steel, chemicals and manufacturing. Africa is already adding mineral processing, manufacturing and digital infrastructure such as data centers, all of which require significantly more reliable electricity. 

Africa is already headed for the fastest growth in electricity demand anywhere in the world. The IEA expects net demand to rise 10.1%, from 799 TWh in 2025 to 880 TWh in 2027, as industrial activity and data centers consume more power. Now add dozens of new cement plants, including some of the largest projects under construction globally. Many are being built in countries that already struggle to keep the lights on.

That creates another opportunity because cement companies need enormous amounts of reliable power and have more incentive to produce some of it themselves. But for cement producers, power costs can determine whether a plant is competitive at all. Pakistan’s Bestway Cement has already installed solar farms across five plants to reduce its dependence on an unreliable national grid. Its Chakwal plant has 26 MW of solar capacity generating more than a quarter of the electricity needed to produce over 3 million tonnes of cement a year.

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The Venezuela International Oil & Gas Summit is taking place nine months after the U.S. captured Nicolas Maduro, installed a U.S.-friendly administration, and vowed to open Venezuela’s oil reserves – the world’s biggest – to development by international companies.

The sold-out event has attracted executives from international majors, regional companies, and relatively unknown petroleum firms, all willing to tap Venezuela’s vast oil riches.

The interim Venezuelan administration, backed by the U.S., has amended the legal and fiscal hydrocarbon framework, making the terms and conditions for investing in Venezuela more attractive for foreign players who are now not bound by sanctions in their operations.

Some companies have already signed deals with Venezuela to explore and operate blocks in the oil-rich Orinoco Belt. Others are considering agreements and investments and are networking at the Venezuela International Oil & Gas Summit. More than 250 companies are attending the event, which has welcomed more than 600 senior-level delegates from more than 30 countries. The summit aims to enable market re-entry for companies and support investment decisions.

The change in Venezuela’s oil fortunes could be best exemplified by ExxonMobil.

Early this year, right after the U.S. extracted Maduro out of Venezuela in early January, Exxon’s CEO Darren Woods told an oil executives meeting with President Trump, “If we look at the legal and commercial constructs—frameworks—in place today in Venezuela, today it’s uninvestable.”

Since January, Venezuela has made changes to the legal, regulatory, and commercial frameworks and has started to attract a broad pool of investors in its oil industry.

Exxon is nearing the signing of a preliminary agreement to explore investments in several Venezuelan oil fields, the Wall Street Journal reported earlier this month, citing sources with knowledge of the discussions.

With a potential deal, Exxon would return to Venezuela two decades after it was forced to abandon the country, after then-president Hugo Chavez nationalized Exxon’s and ConocoPhillips’ assets in 2007. Exxon and ConocoPhillips still seek recovery of billions of U.S. dollars in damages due to the nationalization.

Other oil firms have been less hesitant than Exxon to declare Venezuela investable and sign agreements with state oil firm PDVSA to develop oilfields in the Orinoco Belt or offshore gas fields.

Chevron has pledged over $7 billion in investment over the next five years to more than double its production in Venezuela to about 600,000 barrels per day (bpd).

Continental Resources this month announced a Memorandum of Understanding with PDVSA to operate and develop the Ayacucho 2 Block in the prolific Orinoco Oil Belt. Ayacucho 2, which Continental Resources will operate with a 100% interest, has an estimated 30 billion barrels of resource in place. 

Italy’s Eni signed a strategic contract in Venezuela to become the operator of the giant Junín-5 oil field in the Orinoco Belt. Junín-5, a heavy oil field containing 35 billion barrels of certified oil in place, currently produces around 12,000 bpd.

BP, ADNOC’s international energy investment company, XRG, and Qatar’s UCC Oil and Gas Holding were awarded a license for the Loran offshore gas field in Venezuela, which is northeast of the Orinoco Delta and near Venezuela’s maritime boundary with Trinidad and Tobago.

At the Venezuela summit this week, UCC’s head of upstream, Erik Keskula, said the company was in talks to possibly enter ‌into new fields in Venezuela. 

Colombia-based GeoPark, which operates in Venezuela, plans to invest $7 billion in the Bare oilfield to boost crude oil production to about 90,000 bpd by 2038 from 11,000 bpd now, CEO Felipe Bayon said at the Caracas conference on Tuesday. 

This week’s oil conference in Venezuela will likely produce more deals and investment announcements as the U.S. and the U.S.-backed Venezuelan authorities signal the world’s largest crude reserve holder is open for business again.

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“I have instructed my services to look into the possibilities of postponing the import part of the legislation with one year,” Energy Commissioner Fan Jorgensen told Bloomberg this week. “And this would give the market actors time to make sure that they can indeed implement these new rules without it hurting our security of supply and prices.”

In fact, the main “actors” on the European Union’s gas import market have already protested the methane regulation, which earlier this year prompted the first delay in its implementation. That delay took the form of a no-penalty regime for the first year of the regulation to give importers time to comply, which the two biggest LNG suppliers to the EU said they have no intention of doing.

Both the United States and Qatar have repeatedly spoken out against the methane regulation that would require any company that sells liquefied natural gas to an EU entity to provide information about the methane footprint of its commodity from the well to the tanker.

Qatar directly—and repeatedly—threatened to suspend sales to the EU if the Commission goes ahead with the regulation. As it turned out, it was forced to suspend sales to the EU, leaving the United States as the EU’s biggest LNG supplier. And the U.S. is still very much against the methane regulation.

Delaying the entry into effect of the methane regulation could ensure a steady flow of American LNG, but it will not solve the EU’s price problem—and the EU has a serious price problem, as acknowledged by Jorgensen in recent remarks.

“I want to stress that the Commission is listening to Member States?and to companies, to their call for more flexibility,” Jorgensen said at a news conference this week. “I heard you and indeed there is a number of?things we are looking at to see if we can help more. Methane is one of them. But we are also looking into what we could do to support the availability and affordability of transport fuels.”

The willingness to reduce the financial burden on households and businesses is a positive sign, but the declaration is lacking any specific details. As winter approaches and demand for heating begins to grow as it does every year, the gas supply question is only going to become more pressing—and prices are going to move even higher than they are now. QatarEnergy just extended its force majeure on Ras Laffan for another month, signaling that the resumption of normal LNG flows out of the Persian Gulf is not going to happen soon. Russian gas in any form is about to be banned from January. Norway is pumping as much pipeline gas to the EU as it can. Other suppliers only provide a fraction of imports.

So, it appears that the delay in the methane regulation will address U.S. concerns about LNG trade and ensure a continued flow of liquefied gas to EU member states during the peak demand months of winter. But, again, it will not be doing anything about the affordability of that gas. While there are some long-term supply deals between U.S. producers and European buyers, most LNG is traded on the spot market, and prices there are alarming.

Gas prices on the spot market are currently running at levels last seen in 2022-2023—and supply buffers are much thinner than they were for Europe four years ago. For one thing, gas in storage is lower than the average for this time of the year, although it is steadily rising. For another, back in 2022-23, the EU was still getting Russian gas via Ukraine. Now, pipeline flows are completely cut off. The question the bloc is facing is how long it can rely almost entirely on the United States for its liquefied gas imports, or, to put it more accurately, how long it can afford to rely on U.S. liquefied gas.

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Iranian crude has long been an underestimated part of the global oil balance. After Bashar al-Assad’s government fell in December 2024, breaking the political relationship that sustained Iranian shipments to Syria, China became Iran’s only crude buyer – in 2025, it received an average of 1.4 million b/d. The war initiated by the US and Israel in late February initially made Iran even more important to Chinese buyers: while Tehran blocked other tankers from crossing Hormuz, its own cargoes passed freely, lifting Chinese intake of Iranian oil to around 1.76 million b/d in April.

The more important part of the story, however, was unfolding outside the Strait. Iran had accumulated a vast floating stockpile that allowed deliveries to China to continue even when fresh cargoes could not leave the Gulf. In mid-April, that cushion stood at about 160 million barrels, spread across waters around South, Southeast and East Asia. Drawing on those stocks, China still imported 1.37 million b/d of Iranian oil in May, just 10% below February’s level. But the buffer was shrinking; floating storage fell to 106 million barrels by mid-June before the temporary reopening replenished it to 128 million by mid-July.

That replenishment of available floaters has since stopped. China still received 980,000 b/d of Iranian crude in August, but only 475,000 b/d in September, with arrivals ceasing from September 26 (all of the last arriving cargoes had been loaded in June).

Iran still has around 86 million barrels on the water, the lowest volume since January 2025. Yet 23 million barrels (more than a quarter) are trapped inside the Gulf. The total has barely changed since Chinese arrivals have wound down to an almost complete halt over the past two weeks, with evident loadings in the Kharg island stopping completely. With onshore storage gradually filling up (Kpler data suggests Iranian storage tanks are now 60% full, storing around 70 million barrels), Iran will face the inevitable choice of cutting production. Whilst roughly 2.2 million b/d of production is relatively safe due to demand from its refineries, Tehran’s pre-war crude output of 3.2 million b/d seems to be no longer achievable.

For China’s ‘teapots’ (the smaller independent refineries concentrated in Shandong province), this removes a cornerstone of their crude supply. Accounting for roughly a fifth of Chinese crude imports, these refiners have built their purchasing strategies around discounted sanctioned barrels, particularly from Iran and Russia. Now they must search for barrels farther away, from the Middle East, West Africa and South America. In mid-September, ten Chinese independent refiners reportedly sent traders to Singapore to secure available supplies from the mentioned regions.

The shift is visible at Shandong’s ports. Qingdao, connected by pipeline to 12 independent refineries, relied on Iran for 40% of its 690,000 b/d incoming flows in 2025. In recent months, it has increased purchases of Brazil’s Tupi and Buzios grades and even started receiving Guyana’s Golden Arrow in July, while still relying on Saudi and Russian supplies. Nevertheless, intake has fallen to a record low of around 150,000 b/d over the past three months.

At Dongying, on Shandong’s northern Bohai coast, situated near 32 independent refineries, Russia and Iran supplied virtually all of last year’s 330,000 b/d intake, accounting for two-thirds and one-third respectively. Iranian deliveries started to decrease in summer months, with just two cargoes arriving in August and just one in September. Total intake fell to a mere 220,000 b/d in September as crude-deprived refiners were compelled to cut refinery throughputs.

These refiners are being left with less oil and more expensive alternatives. Guyanese crude is particularly costly when long voyages coincide with an unprecedented shortage of very large crude carriers and record freight rates. To encourage independent refiners to increase runs, the Chinese government issued an additional 28.05 million tonnes of crude import quotas in late September, taking the annual allocation for non-state imports to a record high of 257 million tonnes. These quotas determine how much crude refiners are authorised to import, so the increase gives them room to buy more, but does little to make barrels available or more affordable.

Competition for Russian oil is intensifying, too. Chinese buying has reportedly pushed ESPO differentials to an all-time high premium of $28/bbl vs ICE Brent, while Urals is also trading $7-8/bbl above the same benchmark. Independents must also compete with state-owned buyers, which currently account for roughly half of China’s seaborne crude imports, compared with 45% in February.

China’s recovery is still at an early stage. Seaborne crude imports rose from 7.24 million b/d in August to 7.5 million b/d in September, but remain far below February’s 11.5 million b/d. During April–July, imports had fallen to roughly half that pre-crisis level, depressed by the Beijing-mandated refinery product export ban, lower refinery runs and a gradual shift towards SPRs usage. China’s strategic reserves (both state- and private-owned) remain at 1.12 billion barrels, down from 1.25 billion in April, but rebuilding imports while Iranian supplies disappear will put greater pressure on barrels available elsewhere.

For Tehran, the imbalance is becoming harder to tolerate. Peace negotiations continue without a breakthrough, its crude remains blocked, and its export revenues are squeezed. Meanwhile, oil from neighbouring producers is moving through Hormuz at a surprisingly strong 13 million b/d. That recovery is both a relief for buyers and a vulnerability. As long as Iran cannot export, it has little economic incentive to preserve the arrangement allowing its neighbours’ barrels through. Mounting financial pressure could eventually push Tehran to disrupt those flows, even more than it did ever before.

The market therefore faces two connected risks: China must replace Iranian oil as its demand recovers, and Iran may lose patience with a Strait that is reopening for everyone else. The disappearance of Iranian barrels is already tightening supply. A renewed disruption to Hormuz would make the cost of replacing them much higher.

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