After a Record 2025, LNG Enters a Year of Political Risk

By Irina Slav - Jan 19, 2026

• Geopolitics is colliding with LNG markets early in 2026, as the EU freezes a major U.S. trade deal—including energy purchases—after Trump threatens tariffs linked to the Greenland dispute.
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• Europe remains the largest buyer of U.S. LNG, taking over half of American exports in 2025, but weak industrial demand and political tensions could cap further growth.
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• Asia is set to absorb any surplus LNG, with new global supply likely pushing prices lower and reviving demand in China.
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After a record year for liquefied gas trade in 2025, most forecasts for the new year were upbeat, save for a worry about a possible glut. Two weeks into 2026, however, and one of the biggest markets for liquefied gas is in a geopolitical dispute with its biggest supplier and has put a major energy trade deal on hold. This year is early on turning out to be an anything-can-happen one.

The European Union this week put its trade deal with the Trump administration on hold, stopping short of triggering what it calls the “bazooka” of a mechanism that would wreak havoc on U.S.-European trade relations. The move followed Trump’s declaration of 10% tariffs for eight countries that, according to the U.S. president, are trying to stop him from purchasing Greenland.

The countries in question sent military personnel to Greenland last week to demonstrate that European powers can take care of the island’s security. The tariffs will go up to 25% later in the year if Denmark, Norway, Sweden, France, Germany, the United Kingdom, the Netherlands, and Finland don’t give up and let the United States take over Greenland.

In further escalation and in response to the tariff announcement, Brussels said it would put the massive trade deal that Commission President Ursula von der Leyen closed with President Trump last year on hold. That is the same trade deal that features a commitment on the European Union’s part to purchase $750 billion worth of U.S. energy commodities over three years. It was never going to happen because the EU simply cannot absorb the amount of oil and LNG the sum entails. But it did step up its U.S. LNG buying in 2025—so much, in fact, that it drove the record in global LNG sales with a 25% annual increase in its total LNG imports.

Europe is the biggest market for American liquefied natural gas right now. Well over 50% of all U.S. LNG exports go to the old continent, even as LNG imports from Russia—soon to be banned—also hit a record in 2025. The annual increase in U.S. LNG imports by European countries last year hit a massive 60%, according to Kpler data cited by Reuters’ Gavin Maguire last week.

This should fit in with the bullish forecast context for the industry, but some analysts note that European industrial activity remains weak, as does economic growth—and these are the two driving forces of LNG demand. In other words, European LNG demand could disappoint those with great expectations. And that was before the Greenland affair even began.

Asia, meanwhile, remains the robust LNG market it has been for years, with all the largest LNG importers there rather than in Europe. Last year, 64% of all the world’s LNG for export went to Asian buyers, again according to Kpler data. However, the Asian portion of global LNG exports in 2025 represented an annual decline, to the tune of 5%, Reuters’ Maguire reported. In China, the decline was especially marked, at 15%. That was the result of a combination of factors, including higher domestic natural gas production and higher pipeline imports, notably from Russia.

Kpler earlier this month reported that this year could see LNG capacity additions of 37 million tons annually. That would come on top of new capacity additions totaling 51 million tons commissioned last year. This, according to the analytics firm, would pressure prices, and that would in turn whet buyers’ appetite in Asia, notably in China. These potentially lower prices would see Chinese LNG import demand to rise to 73 million tons this year, Kpler said. This would be up from 68.43 million tons in 2025.

Europe, meanwhile, imported well over 100 million tons of liquefied natural gas last year. For this year, Kpler had forecast a further strong boost to shipments, for a total of some 145 million tons in full-2026 imports. Yet the geopolitical situation could make this difficult to achieve, although it would be harder for the EU to use LNG as a weapon against the United States than vice versa. A souring of bilateral relations across the Atlantic would drive LNG prices lower, which is bad news for producers but bad news with a silver lining—demand from Asia would recover faster.

Among other challenges facing the global LNG trade industry this year is Japan’s restart of more nuclear reactors as energy security trumped any worries about a hypothetical repeat of the Fukushima disaster, and China’s continued drive to boost domestic natural gas output. China’s total gas production for 2025 could reach 263 billion cu m, rising to 278.5 billion cu m this year, thanks to growing shale gas production, Kpler forecast earlier this year. LNG imports into India, meanwhile, also marked a decline last year, highlighting the price sensitivity of many large LNG buyers.

By Irina Slav for Oilprice.com

India Deepens Energy Ties With the Gulf While Balancing Russian Oil Risk

By Alex Kimani - Jan 20, 2026

• India is pursuing a diversified energy strategy, locking in long-term LNG and nuclear deals with partners like the UAE while continuing to buy discounted Russian crude.
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• Energy ties with the UAE are deepening, with new LNG supply agreements, expanded nuclear cooperation under India’s SHANTI Act.
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• Despite rapid renewables growth and falling coal use last year, India will remain a major consumer of oil and coal for decades.

India’s energy strategy is increasingly defined by balance rather than allegiance. As demand surges and geopolitical pressure mounts, New Delhi is locking in long term supply wherever it can, from gas in the Gulf to discounted crude from Russia, alongside nuclear partnerships that promise reliable baseload power. The approach reflects a broader effort to insulate economic growth from volatility, even as global energy markets fracture along political lines. UAE President Sheikh Mohamed bin Zayed Al Nahyan concluded his visit to India’s Prime Minister Narendra Modi on Monday, with the two countries signing a long-term LNG supply deal and agreeing to double bilateral trade to over $200 billion by 2032. The Abu Dhabi National Oil Company (Adnoc) will supply India’s Hindustan Petroleum Corporation with 500,000 tonnes of liquefied natural gas (LNG) per annum in a deal valued at $3 billion, over 10 years beginning in 2028. The deal will deepen energy ties between the two countries, with Adnoc having closed a long-term LNG supply deal with Indian Oil Corp. for 1.2 million tons annually worth between $7 billion and $9 billion, for a period of 15 years.

The two countries also agreed to expand cooperation on nuclear energy, including both small modular reactors and larger conventional projects. The collaboration is supported by India’s recently passed SHANTI Act, which opens parts of the nuclear sector to private participation and foreign partnerships. For New Delhi, the move fits with a broader push to expand low-carbon baseload power as electricity demand continues to rise. For the UAE, it builds on experience gained from the Barakah nuclear plant and supports a longer-term strategy to remain a key energy supplier even as global demand gradually shifts away from oil.

Meanwhile, India continues to buy substantial volumes of Russian oil.

U.S. President Donald Trump recently threatened to slap the country with more tariffs for buying Russian oil, saying, "They do trade, and we can raise tariffs on them very quickly," Trump said about India's Russian oil purchases. Likewise, Republican Senator Lindsey Graham told reporters, "If you are buying cheap Russian oil, (you) keep Putin's war machine going. We are trying to give the President the ability to make that a hard choice by tariffs."

Graham has proposed punitive tariffs of up to 500% on countries that continue to buy Russian oil. Last year, Reliance Industries, India's largest private refiner, significantly reduced purchases after the Trump administration slapped sanctions on Russian energy giants Rosneft and Lukoil in late 2025. The sanctions targeted shippers and traders, causing initial drops in overall Russian oil imports, which were later offset by purchases by state-owned refiners (PSUs). PSUs such as Indian Oil (IOC), Bharat Petroleum (BPCL), and Hindustan Petroleum (HPCL) have maintained or even increased their intake of Russian crude, often through non-sanctioned intermediaries, using long-term contracts.

India is expected to contribute the majority of global oil demand growth in the coming years, leading all other nations, thanks to rapid economic expansion, industrialization, increasing car ownership and rising incomes. 

Indeed, India could account for nearly half of all new oil demand by 2035, with the International Energy Agency (IEA) projecting the country’s energy demand will grow at a 3% annual clip through 2035, the fastest in the world. And, a lot of that growth will come from renewable energy. Last year, India and China recorded the first drop in coal use in more than 50 years, highlighting their ongoing clean energy transition. According to an analysis by the Centre for Research on Energy and Clean Air (CREA), India’s coal-powered electricity generation fell 3.0% year-on-year to 57 terawatt hours while China’s fell 1.6% Y/Y to 58 TWh, marking the first decline since 1973. Faster clean-energy growth accounted for 44% of the reduction in coal and gas consumption; milder weather accounted for 36% while 20% was due to slower underlying demand growth. According to CREA, this is the first time that renewables are playing a significant role in displacing coal from India’s energy mix.

However, India will continue buying and using coal for the foreseeable future, driven by rising energy demand and the need for reliable baseload power, despite significant growth in renewables. India's growing economy and increasing power consumption necessitate coal for grid stability, with plans for more thermal capacity and a projected increase in overall coal demand to 1.5 billion tonnes by 2030.

By Alex Kimani for Oilprice.com

Indian Refiners Boost Middle East Supply To Offset Lost Russian Oil

By Tsvetana Paraskova - Jan 21, 2026

Indian state-run refiner Bharat Petroleum Corporation Limited (BPCL) has awarded tenders to buy Iraqi and Omani crude on the spot market, as India’s refiners are raising supply of crude from the Middle East to offset in part the volumes they lost from Russia following the U.S. sanctions. 

BPCL has awarded one-year tenders to buy Iraq’s Basrah Medium and Oman crude to global commodity trader Trafigura, refining and trade sources told Reuters on Wednesday. 

Additionally, BPCL is scouring the market for spot cargoes of Murban crude from the United Arab Emirates (UAE) in a separate tender, according to Reuters’ sources.  

Over the past weeks, India’s refiners have significantly raised purchases of non-Russian oil supplies as they want to avoid angering the United States amid difficult India-U.S. trade negotiations. 

All Indian refiners have said they would comply with the U.S. sanctions on Rosneft and Lukoil, and Russian supply to India has plunged to a three-year low these days.    

Indian firms are scouring the globe for favorably priced crude to replace the Russian supply they have lost following the U.S. sanctions on Russia’s top producers Rosneft and Lukoil.  

India’s refiners have halted imports from the now-sanctioned entities and turned to non-sanctioned Russian supply and alternative cargoes from the Middle East, the Americas, and, to a lesser extent, West Africa, arbitrage permitting. 

State-run Mangalore Refinery and Petrochemicals Limited (MRPL) is now exploring potential purchases of crude from Venezuela after stopping imports of Russian oil. 

MRPL currently meets about 40% of its crude needs with purchases of Middle Eastern crude. It also buys cargoes on the spot markets and refines domestically produced oil.

The refiner is actively weighing the opportunity to buy Venezuelan crude oil if the commercial terms, including freight rates, are favorable, MRPL’s head of finance Devendra Kumar said on an analyst call last week. 

By Tsvetana Paraskova for Oilprice.com

 

Chevron Approves Leviathan Gas Expansion in Eastern Mediterranean

By Charles Kennedy - Jan 16, 2026

Chevron has approved a major expansion of the Leviathan natural gas field offshore Israel, doubling down on its role as a cornerstone supplier in the Eastern Mediterranean gas market.

The U.S. oil major said on Friday that its subsidiary, Chevron Mediterranean Limited, alongside its partners, has reached a Final Investment Decision (FID) to increase production capacity at the Leviathan offshore platform. The project is designed to raise total gas deliveries from the reservoir to around 21 billion cubic meters per year, up from current levels.

The expansion will involve drilling three additional offshore wells, installing new subsea infrastructure, and upgrading processing facilities on the existing production platform. First gas from the expanded capacity is expected toward the end of the decade, subject to project execution timelines.

Leviathan is one of the largest natural gas discoveries in the Mediterranean and plays a central role in supplying Israel’s domestic market as well as export volumes to Egypt and Jordan. Gas from the field is sent to Egypt via pipeline, where it is used both for domestic consumption and LNG exports to Europe and other markets.

Chevron framed the investment as a strategic move to strengthen regional energy security at a time of rising demand for reliable gas supplies. The company highlighted the role of natural gas as a transition fuel in the Eastern Mediterranean, particularly as countries seek to balance energy affordability, security, and emissions goals.

The Leviathan production platform is located roughly 10 kilometers offshore Dor, Israel. Chevron operates the field with a 39.66% working interest. Its partners include NewMed Energy with 45.34% and Ratio Energies with 15%.

The expansion comes amid sustained interest in Eastern Mediterranean gas assets, driven by Europe’s push to diversify supply following the loss of most Russian pipeline gas. While volumes from Leviathan are modest relative to global LNG trade, the field has become a critical supply hub for the region, supporting Egypt’s LNG export infrastructure and underpinning long-term gas contracts in Israel and Jordan.

Chevron has steadily expanded its footprint in the region since acquiring Noble Energy in 2020. In addition to Leviathan, the company operates the Tamar gas field offshore Israel and is developing the Aphrodite gas field offshore Cyprus. It also holds operated and non-operated exploration positions offshore Egypt.

For Israel, the Leviathan expansion reinforces the country’s ambition to remain a regional gas exporter while ensuring long-term domestic supply. For Egypt, additional volumes could help stabilize LNG exports, which have faced intermittent disruptions due to domestic demand pressures and upstream constraints.

The decision also reflects a broader trend among international oil companies to prioritize gas investments with strong regional fundamentals and existing infrastructure, particularly where projects can be tied into established markets rather than relying on greenfield LNG developments.

Chevron did not disclose the total capital cost of the expansion in its announcement.

By Charles Kennedy for Oilprice.com

 

Mitsubishi Enters U.S. Shale With $5.2 Billion Haynesville Gas Deal

By Charles Kennedy - Jan 16, 2026

Mitsubishi Corporation has agreed to acquire Aethon’s Haynesville shale gas business in a transaction valued at approximately $5.2 billion, marking the Japanese conglomerate’s first direct entry into the U.S. shale gas sector. The deal gives Mitsubishi ownership of upstream gas assets producing around 2.1 billion cubic feet per day across Louisiana and Texas, with clear links to U.S. LNG export infrastructure.

The acquisition covers all equity interests in Aethon III LLC, Aethon United LP, and related entities. Mitsubishi reached the agreement with Aethon Energy Management and its existing financial backers, including Ontario Teachers’ Pension Plan and RedBird Capital Partners. Closing is expected between April and June 2026, subject to regulatory approvals.

The Haynesville Shale has emerged as one of the most strategically important U.S. gas basins due to its proximity to the U.S. Gulf Coast and multiple LNG export terminals. Production from the basin is particularly attractive for LNG-linked strategies because of short pipeline distances, high deliverability, and growing export demand from both Asia and Europe.

Mitsubishi’s newly acquired assets currently produce roughly 2.1 Bcf per day, equivalent to around 15 million tonnes per year of LNG. The gas is sold into the southern U.S. market, with a portion under consideration for export as LNG, including shipments to Japan and European buyers.

The transaction builds on Mitsubishi’s existing North American energy footprint. The company already participates in upstream shale gas development in Canada through a partnership with Ovintiv, operates gas marketing and logistics via Houston-based CIMA Energy, and holds LNG exposure through LNG Canada and Cameron LNG in the United States. Mitsubishi also owns power generation assets through Diamond Generating Corporation.

Notably, the Haynesville assets sit close to Cameron LNG, where Mitsubishi already holds liquefaction capacity under a tolling agreement. This geographic and commercial alignment strengthens Mitsubishi’s ability to control gas molecules from wellhead to LNG cargo, a priority for Japanese buyers seeking long-term supply security.

The acquisition aligns with Mitsubishi’s Corporate Strategy 2027, which emphasizes value creation through integration across business segments. Under its “Create” growth pillar, the company is seeking to build end-to-end value chains that link upstream resources with downstream demand, including LNG, power generation, data centers, and industrial consumers.

For Japan, the move underscores continued reliance on overseas gas assets to underpin energy security, even as the country pursues decarbonization. For the U.S. gas market, it highlights the ongoing appeal of the Haynesville as global LNG demand continues to reshape domestic production and investment patterns.

By Charles Kennedy for Oilprice.com

 

Inside Brazil’s Race to Secure Gas Supply

By Rystad Energy - Jan 17, 2026

• TAG’s compressor, LNG interconnections, and SEAP-linked projects aim to replace LNG imports and unlock domestic gas flows to the Northeast.
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• NTS focuses on reinforcing Southeast corridors to offset falling Bolivian supply and integrate pre-salt production.
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• TBG faces rising supply risk, with biomethane and proposed Argentine imports emerging as critical stopgaps.
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TAG is the gas transmission operator responsible for the main transport corridor connecting Cabiunas, Brazil (Point I), the biggest gas injection point in the country, located from Rio de Janeiro to Ceara (Point O). TAG will play a central role in integrating new domestic gas supply from the Sergipe Alagoas deepwater project (SEAP), liquefied natural gas (LNG) entry points, and demand centers across Brazil’s Southeast and Northeast regions.

The ECOMP Itajuipe compressor station proposal addresses a bottleneck in TAG’s pipeline network that limits gas flow from Southeast to Northeast above the Catu station (K). Installing a compressor on the Cacimbas–Catu (GASCAC) pipeline would add 3 million cubic meters per day (MMcmd) of transfer capacity, raising total capacity from 9.4 to 12.4 MMcmd, enabling domestic gas from the Southeast to replace LNG imports in the Northeast. Currently, LNG imports at Bahia LNG are necessary for the region's high gas power demand. The project aligns with Raia's expected supply from 2028 and is needed until the Sergipe-Alagoas project begins in 2030. Estimated capex is about $150 million.

Since 2024, TAG has been connected to Eneva’s LNG terminal in Sergipe (point L) via a dedicated pipeline, adding a private LNG entry point to the grid. The $65 million project improves short-term supply flexibility in the Northeast and gives Eneva’s Porto de Sergipe I power plant the option to switch between LNG and grid gas based on pricing.

TAG is also evaluating the Gasoduto dos Goytacazes (GASOG) project—a 45.5 km pipeline linking GNA’s LNG terminal at Porto do Acu to the GASCAV system in Campos dos Goytacazes. With an initial bidirectional capacity of 12 MMcmd (expandable to 18 MMcmd), the $190 million project would enable the 3 GW thermal complex at Acu to tap grid gas and unlock new supply sources to meet future industrial demand.

On the supply side, the SEAP development in the Sergipe-Alagoas Basin includes two FPSO-based systems (SEAP I & II). Gas will reach shore via the Rota SEAP offshore pipeline, pre-processed for network injection. While the full pipeline could handle up to 18 MMcmd, only SEAP II—bringing 10 MMcmd—has reached FID. SEAP I, still awaiting FID, could add another 6–7 MMcmd. TAG has already planned the onshore connection, with start-up aligned to Petrobras’ timeline.

Further north, the Veredas project aims to expand capacity into Ceara through a phased duplication of the Nordestao pipeline. Phase I would add 4 MMcmd between Pernambuco and Ceara (points M to O), easing current bottlenecks. Integration with SEAP gas could further meet growing demand in Ceara. Higher volumes will require upstream reinforcements from Cabiúnas or Bahia. Project execution depends on demand commitments, potentially supported by reactivating two thermal power plants in the 2026 LRCAP auction. Estimated Phase I capex is $500 million.

In parallel, TAG and Origem Energia have signed a non-binding agreement to build Brazil’s first gas storage facility using depleted reservoirs in the Alagoas Basin (point L). Initial storage capacity is planned at 100 million cubic meters per year, expandable to 500 million cubic meters, with investment reaching up to $200 million over several phases.

Finally, gas processing capacity is set to grow with PetroReconcavo’s UPGN Miranga in Bahia. The plant will start at 0.95 MMcmd (expandable to 1.5 MMcmd), with operations expected by July 2027 and FID in 2026. With $65 million in capex, the project offers an alternative to Petrobras’ Catu facility, whose shared processing agreement expires in June 2027, giving PetroReconcavo more control over its output.

NTS strengthens network amid declining Bolivian imports and rising pre-salt supply

NTS continues to play a central role in connecting Brazil’s main gas production hubs to its largest consumption centers, Rio de Janeiro and Sao Paulo, together representing over 50% of national gas demand in 2024.

The recently completed GASBEX pipeline links southern Minas Gerais to the national grid via the GASCAR system, delivering up to 0.3 MMcmd to industrial consumers in Extrema and nearby areas. Spanning 28 km with a $40 million investment, the project supports GASMIG’s expansion and helps secure long-term industrial gas demand growth.

The Corredor Pré-Sal Sul aims to expand capacity between Rio and Sao Paulo by duplicating pipelines and adding compression. Once fully developed, it could enable up to 40 MMcmd of interstate flow and 25 MMcmd to TBG via Paulínia (point B), helping offset declining Bolivian imports. However, the first step—the Japeri compression project—has yet to reach FID and is critical to avoiding a potential supply shortfall by 2027. The full corridor remains on hold, with an estimated $1.5 billion capex.

The GASINF project proposes a 100-km bidirectional link from Porto do Acu to the NTS network, enabling either injection of LNG into the grid or delivery of domestic gas to power plants at the port. The $380 million project complements ongoing discussions around an onshore LNG terminal and supports Acu’s ambitions as a gas and energy hub.

A separate project would connect the Sao Paulo LNG terminal to the gas grid. It’s currently under ANP regulatory review and would help offset declining domestic supply in the region by enhancing access to imported LNG and market liquidity for operator Edge.

In January 2025, TAG and NTS completed a new $9 million bidirectional interconnection in Macaé (point I), improving operational flexibility and allowing flows of 2–5 MMcmd. A proposed compressor station (ECOMP Macaé) could boost inter-network flows to 20 MMcmd, but has yet to be approved.

Lastly, the Equinor-operated Raia project will bring up to 16 MMcmd of pre-salt gas from the Campos Basin to the network by 2028 via a 200-km offshore export pipeline. Once operational, processed gas will flow to the Cabiúnas point, supporting domestic supply security and enhancing specification control.

TBG’s supply security hinges on third-party infrastructure decisions

TBG operates the GASBOL corridor, Brazil’s key long-distance gas transmission system linking Bolivian imports to demand centers in the South and Southeast. While new trunklines are not planned, TBG is focusing on optimizing existing infrastructure to boost utilization and diversify supply.

One key initiative is the integration of biomethane hubs, such as Sao Carlos and Porecatu, allowing up to 1 MMcmd of renewable gas to be injected directly into the network. The Sao Carlos hub alone, at an estimated cost of $27 million, will consolidate dispersed biomethane production from Sao Paulo—leveraging nearby sugarcane bagasse—to a single entry point upstream of the Sao Carlos compression station.

However, the withdrawal of New Fortress Energy’s regasification unit from the Terminal Gas Sul has reduced LNG injection options. With Bolivian imports declining to 10–14 MMcmd in 2025 and Argentine imports limited to 0.4 MMcmd/month, alternative sources are insufficient to close the supply gap.

To address this, a new cross-border pipeline from Argentina to Brazil is being proposed, running from Uruguaiana to Triunfo (point D), where it would connect to TBG’s existing network. Estimated at $1.7 billion, the project could transport up to 15 MMcmd but requires Argentina to expand its own pipeline capacity from Neuquén and secure long-term supply contracts with Brazilian buyers. TGN has presented a base case scenario of 10 MMcmd in gas exports to Brazil across multiple routes.

By Felicity Bradstock for Oilprice.com

COMMENT: Instability in Iran bigger threat to global oil markets than Venezuela

Iran has a lot more oil, oil that it is actaully producing and selling, than Venezuela. If that oil goes off line that will be a much bigger problem for global markets and China in particular. / bne IntelliNews

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By Ben Aris in Berlin January 14, 2026

The mass demonstrations rocking Iran presents a far more serious risk to global oil markets than the US decapitation of Venezuela, according to note by Kieran Tompkins, Senior Climate and Commodities Economist at Capital Economics.

Both the scale of Iran’s oil production and the number of potential flashpoints that could disrupt supply make it “a much thornier problem for the global oil market,” says Tompkins.

“Iran accounted for 4.7mn bpd, or 4.4%, of global oil supply last year,” he noted. “That’s despite a backdrop of international sanctions that have caused oil output to fluctuate since the 2010s.” By contrast, Venezuela’s contribution is far smaller, about 800,000 barrels a day in 2025, and market reactions to Operation Maduro on January 3 reflected this. Brent crude prices have risen by approximately 6% since January 8, a movement Tompkins attributes to increased investor perception of geopolitical risk stemming from Iran not Venezuela.

Tompkins warned that some plausible escalation scenarios could “severely” reduce the current global oil surplus, which Capital Economics forecasts at around 3mn bpd in 2024. “Some of these flashpoints could halve that surplus,” he said.

While Iran is also a major natural gas producer — the world’s third largest in 2023, according to the US Energy Information Administration — its impact on the global gas market is limited.

“The country consumes almost all of its gas domestically,” Tompkins noted, with only 1% of global exports in 2023 coming from Iran, mostly via pipeline to Turkey and Iraq. That share has likely declined further due to the continued expansion of global LNG trade.

Looking to the past, Tompkins pointed to historic episodes in which Iranian political instability sharply impacted output. “Oil production peaked at 6mn bpd before the Iranian Revolution,” he said, “but slumped following politically-motivated strikes by oil workers and a flight of foreign expertise.” With exiled Crown Prince Reza Pahlavi now calling for strikes in key sectors, including oil, there are growing concerns that history could repeat itself.

The most severe risks stem from the possibility of military conflict. As bne IntelliNews reported, Arab leaders across the region are lobbying the White House to forego a mooted large-scale military strike on Iran to “help” the protestors. They fear regional instability or a possible regional war and the unleashing of extremist elements.

“That would risk oil infrastructure being targeted, or Iran retaliating by attempting to restrict shipping traffic through the Strait of Hormuz,” Tompkins warned. The strategic waterway handles a fifth of the whole world’s oil transits and LNG shipments; any disruption could send global prices soaring. However, he noted that both outcomes were avoided during the 12-day Israel–Iran conflict in 2025, suggesting that such scenarios remain low probability — for now.

US policy could also factor into the risk calculus. Tompkins recalled that former President Donald Trump threatened 25% secondary tariffs on countries trading with Iran, though similar threats toward Venezuela and Russia did not materialise.

“Iran has increasingly relied on the shadow fleet and a smaller number of buyers,” he said, estimating that China takes in around 90% of Iran’s 1.8mn bpd of seaborne exports.

Looking ahead, Tompkins argued that Iran has the resource base to become a far more prominent energy player — but only if sanctions are lifted and foreign investment returns.

“Iran has the world’s third-largest oil reserves and the second-largest gas reserves,” he said. “But the sector has lacked the technology and investment needed to ramp up production meaningfully.” Even so, low extraction costs in the region mean that, under different circumstances, Iranian oil could be highly competitive.

Iran internet blackout enters seventh day, isolating 90mn people

Netblocks notes longest-ever internet shutdown in Iran. / bne IntelliNews

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By bnm Tehran bureau January 14, 2026

Iran has entered the seventh day of a near-total telecommunications blackout, with the disruption passing 144 hours and ranking among the longest on record, NetBlocks reported on January 14.

The network monitoring organisation said the blackout continues to isolate over 90 million Iranians from the outside world. Network data show the telecommunications shutdown began as nationwide protests erupted across the Islamic Republic.

According to several calls made to Iran by bne IntelliNews, locals were entirely uncontactable; however, several reports suggest that one-way calls to foreign telephone numbers were made. Social messaging apps have also been entirely disconnected, including several Iranian newspapers, who have been entirely disconnected; others have, however, somehow managed to stay online via government internet networks. 

The extended disruption comes as Iran faces its most significant wave of civil unrest in decades. The US-based Human Rights Activists News Agency reported on January 14 that at least 2,571 people have been killed during the protests, a death toll that surpasses any other round of protest or unrest in Iran in decades.

Details of the government crackdown began emerging on January 13 as some Iranians were able to make international phone calls for the first time in days after authorities initially severed nationwide communications when the demonstrations began.

Earlier, on January 14, Iran's judiciary chief Gholamhossein Mohseni-Ejei indicated that authorities would conduct swift trials and executions for detained protesters. US President Donald Trump warned he would "take very strong action" if executions proceed and announced he was terminating negotiations with Iranian leaders.

Iranian President Masoud Pezeshkian said on January 13 that the government's failure to address complaints from merchants and guild members in a timely manner created conditions for the protests, according to Tasnim News Agency.

The telecommunications blackout has prevented independent verification of events inside Iran and hindered communication between protesters and international media organisations. Previous internet shutdowns in Iran during the 2019 protests lasted approximately one week.