<img> The licence specifically covers "transactions for the maintenance of oil or gas operations in Venezuela, including the refurbishment or repair of items used for oil or gas exploration, development, or production activities." The US has cleared the way for American companies to supply equipment and services needed to restore Venezuela's ailing oil and gas infrastructure, in the most substantial expansion of sanctions relief since Washington seized control of the country's energy sector. General License 48, issued on February 10 by the Treasury Department's Office of Foreign Assets Control (OFAC), greenlights "transactions ordinarily incident and necessary to the provision from the United States or by a US person of goods, technology, software, or services for the exploration, development, or production of oil or gas in Venezuela." The licence specifically covers "transactions for the maintenance of oil or gas operations in Venezuela, including the refurbishment or repair of items used for oil or gas exploration, development, or production activities," according to the official text. It also encompasses shipping coordination and port services involving state-run facilities. The measure represents Washington's most significant step yet to facilitate Venezuela's oil sector recovery following the January 3 capture of Nicolás Maduro by US forces. Previous authorisations issued in recent weeks addressed crude trading and imports of chemicals used to dilute Venezuela's viscous petroleum for transportation. However, stringent conditions reflect Washington's intent to retain oversight of the sanctions-hit sector. Contracts with Venezuela's government or state oil company PDVSA must "specify that the laws of the United States or any jurisdiction within the United States govern the contract and that any dispute resolution under the contract occur in the United States," the licence states. Monetary transfers to blocked persons, excluding local taxes, permits or fees, must be deposited into "the Foreign Government Deposit Funds, as specified in Executive Order 14373 of January 9, 2026, or any other account as instructed by the US Department of the Treasury." The licence explicitly prohibits several categories of activity, including "payment terms that are not commercially reasonable, involve debt swaps or payments in gold, or are denominated in digital currency, digital coin, or digital tokens issued by, for, or on behalf of the Government of Venezuela, including the petro [a botched crypto token launched by Maduro in 2017]." It also bars transactions involving entities in Russia, Iran, North Korea, Cuba or China – all close allies of the deposed president – or "any entity that is owned or controlled, directly or indirectly, by or in a joint venture with such persons." The unblocking of sanctioned property and dealings with blocked vessels are also prohibited. Crucially, the licence does not authorise "the formation of new joint ventures or other entities in Venezuela to explore or produce oil or gas," nor does it permit "any transactions or dealings related to the exportation or reexportation of diluents, directly or indirectly, to Venezuela." Firms using the licence must file comprehensive reports with the State and Energy Departments detailing participating parties, goods or services transferred, transaction timing and Venezuelan government payments. Companies must submit initial reports within 10 days of their first transaction, with updates required every 90 days thereafter. The authorisation will open opportunities for oilfield service providers that have advocated for expanded Venezuelan engagement. Halliburton, which exited the country in 2019 due to sanctions compliance, previously stated it requires established commercial and legal frameworks before contemplating a return to operations that once generated approximately $500mn annually. Energy analysts say the licence will assist major service contractors whilst enabling incumbent operators to enhance efficiency at existing facilities. According to Politico, Eric Smith of Tulane University's Energy Institute noted that firms already present, including Chevron and Spain's Repsol, could leverage the authorisation to improve performance at current investments rather than deploying significant new capital. Chevron remains the only significant US producer with Venezuelan operations, allowed by a special waiver, after ExxonMobil and competitors departed two decades ago when former president Hugo Chávez nationalised foreign petroleum assets. The company has reiterated its commitment to US regulatory compliance whilst prioritising operational integrity. Venezuelan production stands at approximately 1mn barrels daily, a far cry from the 3.4mn b/d recorded when Chávez assumed power in 1999. Energy officials estimate output could climb in coming months as sanctions relief enables enhanced operational activity, though the extent remains uncertain without comprehensive infrastructure investment. The licence follows last month's approval by Venezuela's National Assembly of sweeping reforms opening the oil sector to private investment, abandoning more than two decades of socialist policies. Following Maduro’s ouster, acting president Delcy Rodríguez's administration has concluded a $2bn oil supply arrangement with the United States, supporting export recovery after years of restrictions, corruption and mismanagement. Meanwhile, multiple major energy companies including Chevron, Repsol, ENI and Reliance Industries have sought individual authorisations to expand Venezuelan operations. Treasury officials are developing specific licences for firms pursuing enhanced or resumed in-country activities. The first Trump administration slapped comprehensive sanctions on Venezuela's oil sector in 2019 as part of an “maximum pressure” campaign which failed to topple Maduro's regime. Trump has pledged that Venezuelan crude sale revenues will benefit the population, though Washington retains direct oversight of export proceeds as leverage over Rodríguez's interim administration, which is expected to comply with US orders and steer a yet-to-be-defined transition away from Chavismo. The latest authorisation does not permit exploration or production activities, which would require separate licensing. The prohibition on forming new joint ventures signals Washington's cautious approach, seeking to stimulate output without completely normalising commercial relations. Industry specialists say meaningful Venezuelan production expansion would demand sustained multi-year investment to rehabilitate severely degraded infrastructure and restore field productivity following chronic underinvestment. Whether calibrated sanctions relief will attract the necessary capital for comprehensive reconstruction remains unclear. The licence contains no expiration date but can be revoked at any time by OFAC.

Serbia’s Belgrade Stock Exchange plans to introduce trading in carbon credits to help domestic firms manage costs linked to the European Union’s Carbon Border Adjustment Mechanism (CBAM), CEO Lazo Ostojić told Tanjug on February 8. The bourse, which recently adopted the Greek trading system OASIS, is connecting regional capital markets and could eventually join Euronext, the pan-European group that owns eight exchanges. Ostojić said the exchange will create a platform modeled on the EU Emissions Trading System, allowing companies to buy carbon credits to cover carbon dioxide emissions. One credit typically equals one tonne of avoided or stored CO2, letting firms offset emissions by supporting environmentally sustainable projects. CBAM, which came into effect on January 1, requires EU importers of aluminium, cement, electricity, iron and steel, hydrogen and fertilizers from non-EU countries to pay a carbon price. Serbia also introduced a carbon tax—a €4-per-tonne tax on greenhouse gas emissions and carbon-intensive imports—on the same date. The bourse plans additional platforms for digital tokens and CBAM-related trading. Ostojić said companies across the Western Balkans facing similar EU export rules could also benefit from the new carbon credit market.

Serbia and Russia are unlikely to agree on a new long-term gas supply contract due to European Union pressure, market instability and transit risks, Russia’s ambassador to Serbia told Sputnik on February 9, signalling that supplies will instead continue under short-term extensions. Serbia failed to secure a new long-term contract with Russia’s Gazprom last year after Moscow declined to offer a multi-year deal in October 2025. A short-term agreement reached in December expires on March 31, leaving Belgrade dependent on temporary extensions for continued access to discounted Russian gas. Russian ambassador Aleksandar Bocan-Kharchenko told Sputnik that while Moscow and Belgrade had agreed in principle on gas deliveries at acceptable prices, the duration of any contract remained a technical and commercial issue rather than a political one. He said EU energy policy towards Russia had made the gas market more volatile and undermined long-term planning, pushing companies towards shorter, more flexible contracts. Bocan-Kharchenko said Serbia was under pressure from the EU over its energy cooperation with Russia, but denied that Moscow was pressuring Belgrade to abandon its EU accession path in exchange for long-term gas supplies. Another obstacle to a long-term deal was the lack of secure gas transit through Bulgaria, as the EU member state plans to end Russian gas transit by 2028. Serbia’s existing long-term gas supply agreement with Russia expires at the end of March. Srbijagas director Dusan Bajatovic told state broadcaster RTS on February 10 that the deal would likely be extended for another six months. Bajatovic said household gas prices would remain unchanged and that Serbia had sufficient supplies until the end of the heating season. He said daily gas deliveries would fall to about 6mn cubic metres from March, compared with 10mn previously, due to high storage levels. Serbia currently pays around €270 per 1,000 cubic metres of Russian gas, below European spot prices, he added. Gas storage at the Banatski Dvor facility stands at about 400mn cubic metres, Bajatovic said, ensuring supply security even without additional imports in coming months. He said increasing gas supplies from Azerbaijan was not realistic in the short term, while joint gas purchases with the EU were still under discussion. Bajatovic added that Serbia’s Balkan Stream pipeline was operating reliably and remained central to both domestic supply and gas transit, while new interconnectors with North Macedonia and Bulgaria were unlikely to be completed before 2027. Separately, Bocan-Kharchenko said negotiations over the sale of Serbia’s Oil Industry of Serbia (NIS), majority-owned by Gazprom, were nearing completion, adding that Russia was seeking a reliable buyer for the sanctioned asset.

The Egyptian government has requested international oil and gas companies operating in the country to double their production by 2030, Reuters reported on February 10, quoting London-based Energean International (LSE: ENOG) chief executive Nicholas Katcharov. Egypt’s petroleum ministry has intensified upstream activity, bringing around 430 wells into production last year, adding roughly 1.2bn cubic feet of gas per day (cfdb) and more than 200,000 barrels of oil and condensates. The country also recorded 82 new oil and gas discoveries and signed 33 exploration and production agreements in 2025, with minimum investments exceeding $1.6bn. Katcharov said existing petroleum contracts would need to be renegotiated to unlock fresh investment and support higher output, particularly in redevelopment projects at mature fields. He noted that the low domestic gas prices, which underpinned earlier development phases were no longer viable, arguing that fiscal terms must be updated to reflect current market realities. “There is a significant gap between local gas prices in Egypt and the cost of imported gas,” Katcharov said, adding that while it was difficult to pinpoint an exact price, incentives would be required to stimulate new capital spending and production growth. Katcharov also said Egypt had recently repaid $80mn of outstanding dues to Energean, reducing arrears that had previously exceeded $200mn. He expressed confidence in the Ministry of Petroleum’s ability to settle the remaining balances. He added that gas flows from Israel into Egypt had increased in recent months. As of February 2026, the Egyptian government has successfully cleared approximately $5bn in outstanding arrears to international oil companies, reducing the debt from a 2024 peak of $6.1bn. Following recent liquidity injections from regional deals, the country aims to slash the remaining balance to $1.2bn by June 2026 while maintaining the regular settlement of current monthly invoices. Energean operates the Abu Qir concession in the West Nile Delta, one of Egypt’s largest gas-producing hubs, comprising the Abu Qir, North Abu Qir and West Abu Qir fields.

Egypt has signed two grant agreements worth a combined €125mn with the EU to support renewable energy expansion and the development of green ammonia projects, Al Borsa reported on February 10. The first grant, valued at €90mn, will be managed by the European Investment Bank (EIB) and is aimed at strengthening Egypt’s electricity grid and expanding renewable energy capacity. The second grant, worth €35mn, will support a green ammonia project in Ain Sokhna being developed by Norway’s Scatec (OSE: SCATC), as part of Egypt’s broader push into low-carbon fuels and green industrial exports. The agreements were signed during an EU-hosted conference titled “The Future of Sustainable Energy in Egypt 2040: Cooperation for Shared Prosperity”. The shift toward secure, efficient and sustainable energy systems is a key driver of Egypt’s comprehensive development agenda, supporting economic competitiveness while meeting climate commitments. Egypt’s 2040 energy vision focuses on expanding renewables, improving energy efficiency and maximising the use of diverse resources to reinforce the country’s role as a regional energy hub in the Eastern Mediterranean. The strategic partnership launched between Egypt and the EU in March 2024 marked a turning point in bilateral relations, with energy at its core through blended finance, investment guarantees and technical assistance. The €7.4bn Strategic and Comprehensive Partnership elevated Egypt-EU relations to their highest level, focusing on macroeconomic stability, investment, and security. The package included €5bn in concessional loans and €1.8bn in investments to support Egypt's economic reforms, alongside specific grants for migration management and the green energy transition. In addition, the EU’s EFSD+ mechanism and Egypt’s NWFE platform have mobilised climate finance and accelerated green growth.

Mexico’s decision to suspend oil shipments to Cuba while expanding humanitarian aid has exposed the limits of its room for manoeuvre under renewed US pressure, as well as the depth of Cuba’s escalating energy and economic crisis. The move reflects a careful recalibration by President Claudia Sheinbaum’s government, which is attempting to shield Mexico from punitive tariffs threatened by Washington while avoiding a complete rupture with Havana. At the centre of the dispute is a January executive order signed by US President Donald Trump declaring a national emergency with respect to Cuba and authorising sanctions and secondary tariffs on any country supplying oil to the island. This followed the US military intervention in Venezuela, long Cuba’s main energy provider, and the subsequent collapse of already dwindling fuel flows from Caracas in the wake of the ouster of Nicolas Maduro. According to Bloomberg, Mexico had effectively become Cuba’s principal oil supplier in recent months, covering close to 80% of its imported crude needs together with Venezuela last year, based on data from Kpler. Sheinbaum confirmed this week that all oil shipments are currently “detained”, explicitly citing the need to avoid economic retaliation against Mexico from its key trading partner. While rejecting the legitimacy of the broadening US embargo, she acknowledged that continued exports could trigger tariffs affecting Mexican trade. The suspension marks a sharp reversal from late 2024, when oil deliveries to Cuba increased significantly and were partly classified as humanitarian aid following Hurricane Rafael. The scale of the commercial relationship underscores the sensitivity of the decision. Official data released by the Mexican government and cited by El País show that Petróleos Mexicanos (Pemex), through its subsidiary Gasolinas Bienestar, sold nearly $1.5bn worth of crude and petroleum products to Cuba between 2023 and 2025, at market prices and under contracts denominated in pesos. In 2024 alone, average exports reached over 20,000 barrels per day, equivalent to 2.8% of Mexico’s total crude exports. Pemex executives stressed that the arrangement was commercial rather than concessional, and that Cuba had remained current on payments. For Cuba, however, the halt has had immediate consequences. The communist-run island recorded its first month with zero oil imports in a decade in January, according to shipping data cited by Bloomberg. Despite recent efforts to diversify its electricity matrix with Chinese-made solar plants, Cuba generates over 80% of its electricity from oil, with stuttering thermal power plants – many of Soviet design – relying heavily on both domestic crude and, predominantly, imported fuel. As a result, oil shortages have rippled across the economy: aviation fuel supplies have been exhausted, forcing authorities to warn international airlines that they cannot refuel on the island, several major tourist resorts have shut down, and queues at petrol stations in Havana have stretched for hours. Cuban officials have previously acknowledged that national gasoline demand stands at roughly 8,200 barrels per day, a level that Mexican shipments had only just managed to cover for about a month at a time. The humanitarian impact has been even more severe. Hospitals have suspended surgeries, restricted patient transfers and run critically low on diesel, medicines and basic supplies. Public transport networks have effectively collapsed in several provinces, with long-distance bus and ferry services curtailed due to lack of fuel, as reported by Cuban state media. Food rationing has intensified, with staples reportedly sufficient for only a few weeks. Against this backdrop, Mexico has opted to maintain and expand non-energy assistance. Two Mexican navy vessels—the Papaloapan and Isla Holbox—departed the port of Veracruz carrying 814 tonnes of food and hygiene supplies, including rice, beans, canned fish and powdered milk. Further consignments, amounting to more than 1,500 tonnes of additional supplies, remain pending Sheinbaum has framed the aid as a humanitarian obligation detached from ideological alignment, arguing that sanctions “should not strangle people”. Diplomatically, Mexico has positioned itself as a potential intermediary. The president has said her administration is pursuing channels with Washington to find a formula that would allow Cuba to receive fuel without triggering sanctions, while the Havana regime has moved from defiance to some degree of willingness to engage with the Trump administration, albeit without placing political reform on the table. Sheinbaum's policy illustrates the tension facing middle powers under intensifying US sanctions regimes, as governments are forced to balance economic self-interest, regional solidarity and humanitarian considerations. The suspension of oil exports may protect Mexico from immediate retaliation, but it removes one of the last buffers cushioning Cuba from a rapidly deepening energy shock, leaving humanitarian aid as an imperfect substitute for the fuel that underpins the island’s basic services.

Russia is still exporting oil to India. At least that is what New Delhi – and Moscow - claim. Half a world away meanwhile, Washington has repeatedly announced that New Delhi is on the cusp of a clean break, something Indian officials have been far more cautious about as they stress diversification and energy security rather than outright cessation. At the heart of the dispute lies a set of data with real economic heft. India, as one of the world’s largest crude importers and in recent years at least a major buyer of Russian crude, in the fiscal year to March 2025, saw Russia as its single largest oil supplier. Data suggests that roughly 1.76mn barrels per day (bpd) which made up around 36% of its total crude imports according to ship-tracking and energy data, arrived from Russia. This was an increase of 7.3% on Russian oil imports compared to the year before and came about primarily as a result of the discounts being offered by Moscow. Overall, India’s total import portfolio that year averaged close to 4.9mn bpd, with the more traditional Middle East suppliers such as Iraq and Saudi Arabia falling behind Russia in terms of total volume shipped. These figures alone demonstrate why the ongoing public dispute between New Delhi and Washington has gone beyond mere technicalities into something approaching oil-supply theatre. In Washington’s telling, India has repeatedly agreed to halt direct or indirect purchases of Russian crude as part of a wider trade and tariff deal. When US President Donald Trump’s administration touted the lifting of punitive tariffs as a reward for such a shift, officials in Washington claimed – repeatedly but incorrectly it now appears - that India’s Russian crude imports were on the verge of stopping. Other claims based on Indian imports dropping from a mid-2025 peak of over 2mn bpd to just under half that were also seen as proof that New Delhi had given in to US pressure and was shifting away from Russian oil imports. Yet Indian official responses in the past month have been particularly guarded. In one press briefing held in response to US comments, Indian Foreign Secretary Vikram Misri confirmed New Delhi’s overriding intent towards “maintaining multiple sources of energy supply”. In making this statement he effectively posited that any reductions in Russian oil imports would only be made as part of a broader diversification strategy rather than a capitulation to US tariffs pressure. As such, contested Indian-US narratives have caused a great deal of confusion depending upon the source. In recent days, Reuters reporting indicates that Indian state refiners such as Indian Oil Corporation, Bharat Petroleum and Reliance Industries have now declined trader offers for Russian crude for an April 2026 delivery date. While this does suggest a slowdown of sorts for now with trade negotiations it does not signal any form of abrupt stop. Moreover, crude import statistics show that Russian oil flows remain significant to New Delhi. India’s imports of Russian crude, which hit a multi-month low in December 2025 in dollar terms at around $2.7bn, have since bounced back according to Kpler and trade data. Reuters reports that in January 2026 India was still importing around 1.2mn bpd of Russian crude – a marked decline from the peak, but still far from the zero claimed by the US. To this end, while India appears to be reducing its dependency on Russian crude it is not eliminating it wholesale. It is correct to say that Indian refiners have been actively purchasing barrels from elsewhere, including Venezuelan crude recently bought by IOC and HPCL for delivery later in 2026, but this is a sign that New Delhi is simply broadening its supply base as it originally claimed. In addition, there are a number of technical and economic reasons why a sudden stop is unlikely. Primarily this centres on the fact that Russia’s Urals grade crude has historically been sold at discounts relative to Middle Eastern and US benchmarks – a significant factor for India. Refining infrastructure on the subcontinent is also tailored to heavy, sour crudes like those from Russia and Venezuela, making these supplies economically more attractive even as Washington encourages alternative sources. These nuances are lost in much of the rhetorical sparring as Washington ties the narrative of India stopping purchases outright to the wider sanctions regime imposed on Russia. In Delhi and Moscow meanwhile, officials have pushed back against any concept that India is moving away from its longstanding energy deals with Russia, stressing the fact that New Delhi’s position has always been that supply decisions will be driven by India’s national interest as well as market conditions. What results is a reflection of India’s size and energy hunger – that New Delhi is willing to rebalance, but not repudiate.

Bangladesh’s industrial slowdown has become one of the clearest warning signs that the country’s energy strategy has reached a point of severe strain. What began as a manageable rise in fuel imports in recent years has now hardened into an all-out structural vulnerability, with shrinking domestic gas supplies coupled to a growing reliance on LNG as well as coal and oil imports forcing factories to cut output and rethink expansion plans. The resulting energy woes are causing a drag on economic momentum that now finds itself in the political spotlight as voters head to the polls on February 12. Energy specialists in Bangladesh and elsewhere in Asia had sounded the alarm long before the shock of the Russia-Ukraine war exposed the fragility of global fuel markets. Bangladesh had long depended on imported petroleum for transport, irrigation and cooking, The Business Standard – a local publication – reported recently, but that dependence deepened when the country chose not to mine domestic coal, largely on environmental and social grounds. In turn this left it heavily reliant on imported coal to fuel roughly 6,000-MW of coal-fired power capacity. What few anticipated though, was the speed with which natural gas, regarded as a domestic strength, would also turn into import dependence once local fields started drying up. As recently as a decade ago, locally produced gas met about 80% of Bangladesh’s commercial energy demand, but years of underinvestment in exploration and development under the Hasina government steadily eroded that cushion. By 2018, the government had little choice but to turn to LNG imports to help bridge the energy gap. As a result, today, domestic gas supplies account for less than 40% of energy needs. These numbers illustrate only a small portion of the scale of the shift. Energy import dependence stood at around 20% in 2015 the same report said. Within seven years that number had more than doubled, and by 2024, the year Hasina fled to India, it is estimated to have exceeded 56%. Because of this, and without major new gas discoveries or a rapid acceleration in renewable energy deployment, it is more than likely that import dependence in Bangladesh could climb towards 90% by the end of the decade, effectively signalling the total depletion of commercially viable domestic gas reserves. This transition has come at a high price. Foreign currency outflows linked to energy go far beyond the visible bill for LNG, oil and coal imports. Bangladesh is now also paying international oil companies, for gas supplied to the national grid. This is a bill that reaches around $500mn a year. Other payments to power producers, excluding the Indian Adani-linked plant, are estimated at around $4bn annually. On top of that are the foreign-currency costs of building, maintaining and financing energy infrastructure across the gas, oil and power sectors. None of these come cheap and loan repayments alone add several billion dollars more each year. Taken together, the foreign currency obligations of the energy and power sectors in Bangladesh are estimated to exceed $20bn annually according to The Business Standard, and if authorities in Dhaka were to meet full gas and electricity demand through additional LNG and oil imports, that figure could rise towards $24bn in all. However, with demand continuing to rise, cutting energy supply is not a realistic option. To this end, incoming policymakers after the February 12 election will have two choices: boosting domestic energy production, particularly gas from existing but some almost depleted sources, and accelerating the deployment of renewables, above all solar. Petrobangla’s supposed plans for well drilling programmes would be widely welcomed, but scepticism remains over whether they will be implemented at all. Offshore exploration, especially in deep water, has now been delayed for so long that Bangladesh has essentially forfeited years of potential production whilst expertise through retirement has also been lost. Renewables to some degree face similar challenges as Bangladesh’s renewables capacity remains below 6% at present. Most sources put this figure closer to 4-5%. The bulk of this is solar in form with a limited amount of hydropower. There si very little wind capacity in the country. Any incoming government would need to coordinate action and look into land allocation for increased solar projects or even wind farms whilst also streamlining approval methods at the very least. And then there is the nuclear option. Nuclear power, anchored by the Rooppur project in the west of the country promises long-term baseload capacity but raises questions about financing, safety and institutional readiness. It is not a time to abandon the nuclear option though – particularly with the Rooppur nuclear power plant set to come online in the coming months after years of joint development with Russia. As such, whichever party comes out on top in the election, the next administration will have limited room for manoeuvre and little time to lose. Decisions taken soon after the ballots are counted will determine whether Bangladesh can stabilise its energy system - or not. In the two days left before the polls open therefore, voters must give serious consideration to energy security, which, although once treated as a long-term concern, has now become an immediate test of economic management.

Moroccan aviation authorities have imposed an unprecedented set of requirements on all international airlines flying into the country, requiring them to adjust their fuel planning ahead of departure due to temporary constraints on the availability of jet fuel at Moroccan airports, Al Arabiya Business reported on February 9, citing an official Notice to Air Missions (NOTAM) issued by Morocco’s Flight Information Region (GMMM). The measure is intended to preserve strategic fuel reserves, prioritise emergency needs, and maintain flight schedules without major disruption, particularly for aircraft unable to carry return fuel due to capacity or performance constraints. The new measures came into force on February 7 and will remain valid until February 13. The instructions apply to all inbound flights without exception, including scheduled commercial services, charter operations and cargo flights. Under the new protocol, airlines operating wide-body aircraft are required to uplift the maximum possible amount of fuel at their departure airports, within technical performance limits and in full compliance with safety regulations, particularly maximum landing weight restrictions. For narrow-body and medium-haul aircraft, operators have been instructed to apply a fuel tankering strategy, loading sufficient fuel to cover both the outbound and return flights, thereby avoiding refuelling at Moroccan airports during the affected period. The NOTAM allows for limited flexibility in exceptional circumstances. Refuelling within Morocco is permitted only at the minimum level required under aviation safety protocols to ensure safe onward operations, with authorities stressing that local refuelling should be kept to an absolute minimum.

Egypt has invited German renewable energy companies to invest in green hydrogen projects across the country, Al Masry Al Youm reported on February 9. Egypt’s Minister of Investment and Foreign Trade, Hassan El-Khatib, called on German companies to take advantage of the promising investment opportunities available in the green hydrogen sector, particularly within the Suez Canal Economic Zone (SCZone), and to expand their investments in Egypt. The remarks came during the seventh meeting of the Egyptian-German Joint Economic Committee. Seeveral frame work of agreements were signed by El-Khatib and Stefan Rouenhoff, Parliamentary State Secretary at the German Federal Ministry for Economic Affairs and Climate Action. The two sides agreed to enhance cooperation through exchanging expertise in supporting small and medium-sized enterprises (SMEs), entrepreneurship, business facilitation, technology transfer, digitalisation of SMEs, and innovative financial tools for startups. The meeting was attended by Mohamed El-Goski, CEO of the General Authority for Investment and Free Zones (GAFI); Abdel Aziz El-Sherif, Head of the Commercial Representation Authority; and Ahmed Badawy, Head of Promotion Sector at GAFI. During the discussions, both parties agreed to explore industrial investment opportunities, covering 28 promising industries. Egypt also offered a package of incentives for the industrial sector and provided informational booklets on Robbiki Leather City to encourage German companies to invest. Both sides exchanged updated laws and procedures related to industrial investment. The Egyptian side invited the German business community to benefit from Egypt’s trade agreements with Africa, including the African Continental Free Trade Area (AfCFTA) and COMESA, as well as the Greater Arab Free Trade Area, enabling access to large consumer markets. Germany was also encouraged to support the EU-Mediterranean Partnership Agreement, particularly its rules of origin.

Nigeria’s 650,000 barrels per day (bpd) Dangote refinery is expected to begin test runs at full nameplate capacity this month after maintenance on its Residual Fluid Catalytic Cracker (RFCC) is completed, according to comments made by a senior executive on February 4. Once test runs begin, the plant will be able to move towards more reliable, year-round operation – a notable improvement following ongoing uncertainty around the plant’s maintenance schedule and performance. On the route towards full capacity, Dangote has been running at between 450,000 and 480,000 bpd. Increasing this to 650,000 bpd should help the $20bn plant ease pressure on the country’s currency by reducing demand for the dollar. It will also likely change regional oil flows as the refinery becomes the continent’s dominant producer, according to Hydrocarbon Processing. Despite being Africa’s largest oil producer, Nigeria still relies heavily on fuel imports, and Dangote will play a large role in reducing this dependence. Regarding progress towards full capacity, Dangote Refinery’s managing director, David Bird, said that he expected the facility to run consistently this year. “We've now completed the maintenance we planned on our critical equipment, and in February, we will conduct performance test runs at full capacity.” He said, underscoring that: “This is the year we sustain full nameplate capacity.” Bird continued to note that the refinery also had enough of a design margin to increase capacity to 700,000 bpd once its performance had been showcased to insurers. The executive remarked: “I don't want it misunderstood – our insurance today is 650,000 bpd, but we think the design can support 700,000, and we will engage the insurance market once we prove that.” Bird also assured that it was normal for large greenfield refineries to go through a ramp-up period of 18 to 24 months following initial startup before continuing into more predictable commercial operation, and said that early maintenance had been conducted to “iron out all the bugs,” and that the crude distillation unit had been operating reliably and safely non-stop since January 2024.

A Glencore shareholder is set to invest R6bn ($326mn) to upgrade Astron Energy’s 100,000 barrels per day (bpd) Cape Town petroleum refinery, committing to reinforcing the country’s energy sector amid difficult times. The investment, made by Ivan Glasenberg, has become one of the largest commitments in South Africa for numerous years, according to Billionaires Africa, and signals the importance of the refinery, which has now become a focal point in plans to turn Astron Energy into a stronger regional player as part of efforts to increase exports. Moreover, as the plant remains South Africa’s third-largest refinery, Astron also plays a vital role in local fuel supply, particularly as the country has continued to place a heavier emphasis on fuel imports to support its economy. According to industry analysts, the refinery acts as an economic anchor, allowing for the creation of R95bn in revenue while also supporting around 50,000 jobs. Glencore’s CEO, Gary Nagle, has repeatedly stressed that the refinery is cash generative, with the latest cash injection seemingly supporting the position. A boost from Glasenberg will allow Astron to upgrade the facility, improving output and efficiency, as well as extending its life. The project is also shown in Nedbank’s Capital Expenditure Project Listing 2025, which has highlighted a rebound in private sector spending amid weakened public finances. Astron’s refinery (also known as the Milnerton plant) only recently re-started its operations in 2023, with the company noting at the time that it planned to fully recommence the production of refined products for supply into the Western Cape and the wider South African regions. Commitments to reopen, and indeed invest in the facility, are at odds with ongoing trends in South Africa, where, due to clean energy regulations, some oil and gas refineries have been choosing to shut down rather than invest in refurbishment and upgrades. In the recent past, the refinery had been closed until 2020, following a deadly fire that damaged the facility, killing two engineers in the process. Glencore first acquired it in 2019 as part of a $1bn deal with Chevron and had recently completed a $400mln upgrade to the facility to allow it to produce low-sulfur fuel. Spokesperson for Astron Energy, Suzanne Pullinger, said in 2022 regarding the restart that “the refinery forms a significant part of the Astron Energy business, and it remains our intention to safely restart by the end of Q4 2023 . . .with a key focus on maximising safety for the restart and beyond.” Notably, South Africa’s Minister of Mineral and Petroleum Resources Gwede Mantashe has previously highlighted concerns about investment, saying in 2022 that: “While we appreciate the return to full operation of the Cape Town refinery, we are also mindful of the need for investments in a new refining capacity, particularly in light of the recent oil and gas discoveries both in the South African and Namibian waters.” With this in mind, a cash injection from Glencore will likely be positive news, particularly as South Africa continued to see a record increase in imported fuels following the shutdown – either temporary or permanent – of several domestic refineries.

BP is actively canvassing for a partner to share the capital burden of redeveloping the historic Kirkuk oilfield, as the British supermajor accelerates its pivot back toward high-margin hydrocarbon growth. According to sources cited by Bloomberg last week, a process is underway to identify investors willing to share costs and technical responsibilities for the project in northern Iraq, though any formal agreement is likely to extend into next year. The search for a partner underscores BP’s renewed commitment to the Middle East, a region offering lower production costs compared to other global basins. This follows the company’s strategic recalibration away from an aggressive reduction in oil and gas output, as it seeks to shore up earnings. The Kirkuk development contract, a cornerstone of BP’s Iraqi portfolio alongside the southern Rumaila field, covers the rehabilitation of the Baba and Avanah domes, as well as the adjacent Bai Hassan, Jambur, and Khabbaz fields. Reuters reported on 4 February that BP is expected to invest between $20bn and $25bn over the course of a 25-year profit-sharing agreement (PSA). The commercial terms link BP’s remuneration to its ability to boost output while containing costs. Iraq’s Oil Minister, Hayyan Abdul Ghani, has stated that the objective is to double production capacity from the current level of just over 300,000 barrels per day (bpd) to around 600,000 bpd. Bloomberg sources indicated that annual operating costs are projected to be in the region of $1bn. While BP structures the long-term investment framework, the state-owned North Oil Co. (NOC) has already commenced interim rehabilitation works. Shafaq News reported that NOC has successfully reactivated 35 dormant wells across the Kirkuk region, including 17 in the Bai Hassan field and seven in the main Kirkuk reservoir. Amer Khalil Ahmed, NOC’s director general, told Shafaq News that technical teams are intensifying operations at the Sarlu and Sarbashakh stations to sustain this momentum. In early 2025, production stood at roughly 330,000 bpd, the majority of which is allocated to domestic refining, with a residual 10,000 bpd exported to Jordan. The redevelopment of Kirkuk is critical to Baghdad’s wider ambition of raising national production capacity to 6mn bpd by 2029. However, the project remains sensitive to the complex political dynamics between the federal government and the semi-autonomous Kurdistan Regional Government (KRG). Exports from the north have been suspended since March 2023 following an International Chamber of Commerce arbitration ruling that halted flows through the Iraq-Turkey pipeline. However, legislative breakthroughs in Baghdad may signal a thaw. Shafaq News reported that the Iraqi government recently approved budgetary amendments designed to resolve fiscal disputes with Erbil. Deputy Speaker Shakhawan Abdullah noted on 2 February that “the obstacles to oil exports from the Kurdistan Region have been resolved,” potentially clearing the way for northern crude to reach international markets once more. For BP, the successful rehabilitation of Kirkuk – discovered by its corporate forebears in 1927 – would cement its position as a dominant player in Iraq’s energy sector, balancing its exposure between the southern giants and the northern frontier.

Abu Dhabi National Oil Company (ADNOC) is expected to take a significant minority stake in Serbian oil company Naftna industrija Srbije (NIS) as part of a deal to acquire Russian Gazprom Neft’s holding, Serbia’s energy ministry said on February 5. Russia’s Gazprom and its oil arm Gazprom Neft agreed in January to sell their combined 56.15% stake in NIS to MOL, a move that could allow US sanctions on the company to be lifted if approved by Washington. ADNOC is expected to take a minority holding in a joint company with MOL that would become NIS’s majority owner. Energy Minister Dubravka Dedovic Handanovic discussed future cooperation in Serbia’s oil sector with ADNOC executives in Abu Dhabi on February 5, as the UAE state-owned company holds advanced talks with Hungary’s MOL to buy part of Gazprom Neft’s stake in NIS. “It is important for us because ADNOC is a state-owned company with extensive experience in the oil sector and an understanding of state interests,” Dedovic Handanovic said, according to a statement issued by the ministry. NIS, which owns Serbia’s only oil refinery in Pancevo, was sanctioned by the US Treasury’s Office of Foreign Assets Control (OFAC) in October as part of measures targeting Russia’s energy sector over Moscow’s war in Ukraine. The sanctions disrupted oil supplies and forced a temporary shutdown of the refinery, raising concerns over fuel shortages. The United States has since granted a sanctions waiver allowing NIS to continue operating until February 20, after Russia agreed to divest its majority stake. Dedovic Handanovic said ADNOC had confirmed its goal was to keep the Pancevo refinery operating and to expand capacity in line with market demand. She added that in-depth analysis related to the transaction would be completed by the end of February, with the aim of signing the purchase agreement by March 24, the deadline set by OFAC. OFAC approval is required for the deal to proceed and for sanctions on NIS to be lifted. Under the proposed structure, MOL would manage NIS as the majority shareholder in the joint company, while ADNOC would hold a significant stake and participate in management bodies.

The world faces escalating and uneven costs from climate adaptation as rising temperatures, extreme weather events and sea-level rise strain public finances and economic productivity, according to new research from the McKinsey Global Institute. In its report “Advancing adaptation: Mapping costs from cooling to coastal defences,” published in February, McKinsey warns that the financial burden of adapting to climate change will grow significantly over the coming decades, particularly in low-income and high-exposure regions. Just the cost of air conditioning is going to take up 40% of all adaption costs, according to the consultancy. Currently the world spends around $190bn a year on climate related damage, but that spending will rise to 41.2 trillion a year when temperature increases above the pre-industrial base line rise above 2°C. The temperature increases have already crossed the 1.5°C Paris target in 2025 for every month of the year. Previously, the 2°C threshold was forecast to come in 2050, but with an intense El Niño forecast to start in a few month’s time, the United Nations’ Intergovernmental Panel on Climate Change (IPCC) models are now predicting the deadline to. Reach 2°C above the baseline is likely to arrive as soon as 2030. The Climate Crisis is accelerating. The IPCC says that the Paris Agreement goal of keeping temperature increases to less than 1.5°C-2°C above the pre-industrial benchmark has already been missed and temperature increases are on course to reach a catastrophic 2.7C-3.1C by 2050. At that point extreme temperature events will become routine and large parts of the world will become uninhabitable. In just the last two years green bonds have gone mainstream as the annual cost of extreme weather events are increasing exponentially and demand for wildfire catastrophe bonds is also rising fast for the same reasons. The Climate Crisis is here and it's already doing a lot of expensive damage. The McKinsey report also tallies with an environmental damage impact report released by Fitch last week that warns exposed countries risk having their ratings downgraded by several. Notches due to exploding extreme weather damage or the transition costs of failing to move away from an economic dependence on fossil fuels. McKinsey mapped over 200 adaptation responses across 80 geographies, focusing on five key areas: liveability and workability, food systems, physical assets, infrastructure services, and natural capital. “Adaptation costs are rising and will differ widely across regions, sectors, and income levels,” the report said. “The challenge is not just about mobilising capital—it’s about doing so in a way that delivers equitable resilience.” McKinsey noted that while global attention has focused on mitigation—reducing greenhouse gas emissions—adaptation investment remains inadequate, even as climate hazards intensify. In many countries, the impact is already measurable. For example, extreme heat could reduce effective working hours by up to 20% in some regions by 2050, with outdoor labour and low-income workers bearing the brunt. “Without adaptation, productivity losses from heat exposure alone could exceed 2% of GDP in the hardest-hit regions,” McKinsey said. This includes parts of South and Southeast Asia, Sub-Saharan Africa, and the Middle East. Cooling demand is expected to surge as a result, with residential and commercial cooling accounting for up to 40% of electricity demand in hot, fast-growing countries by mid-century. However, access to cooling is still highly unequal, creating both a human and economic vulnerability. “Closing the global cooling gap is one of the most urgent adaptation imperatives,” the report noted. Sea-level rise and coastal flooding present another costly frontier. McKinsey estimates that $1.7 trillion to $2.4 trillion of GDP could be at risk annually by 2050 without adaptation, particularly in low-lying urban centres in Asia. Even modest investments in coastal protection—such as sea walls, wetland restoration, or building codes—could significantly reduce that exposure. The report also highlighted the vulnerability of food systems to shifting rainfall patterns and water stress, warning that “agriculture in water-scarce regions will require both technological adaptation and significant capital to maintain yields.” Critically, McKinsey argued that the economics of adaptation are context-dependent, with a strong case for action even in poorer regions. “Many of the most effective responses have positive net benefits over time,” the report said. “The barrier is often not cost—but coordination, financing mechanisms, and governance capacity.” Despite the risks, global adaptation finance remains far below the levels required. The UN Environment Programme estimates a financing gap of $194bn to $366bn per year by 2030, far exceeding current commitments. “The costs of adaptation will be substantial,” McKinsey concluded. “But the costs of inaction will be far greater—economically, socially, and environmentally.”

The International Energy Agency warned that while global electricity demand is set to surge over the next three years, the benefits of clean energy investment and rising renewable output remain unevenly distributed, threatening to deepen the divide between advanced and developing economies. The “Age of Electricity” is here and half the world’s power will be generated by renewables and nuclear power plants (NPPs) by 2030, the IES says in its latest “Electricity 2026” report. The IEA projected that global electricity demand will grow by nearly 3.4% annually through 2026, with demand from emerging and developing economies—particularly in Asia—driving most of the increase. However, the agency cautioned that infrastructure constraints, financing gaps, and persistent energy poverty risk leaving large parts of the Global South behind. “We are seeing two very different realities emerging in electricity markets,” the IEA said. “In advanced economies, growth in demand is modest, while renewables are increasingly supplying that growth. But in many developing economies, electricity demand is rising rapidly and grid investment is struggling to keep up.” By 2025, the report forecasts that more than one-third of global electricity generation will come from renewables, with solar PV and wind accounting for the bulk of new capacity additions. The share of low-emissions generation—including renewables and nuclear—is expected to rise from 39% in 2023 to 50% by 2026, largely displacing coal-fired generation in major economies such as China and the US. “Electricity is becoming cleaner, thanks to the spectacular growth of renewables,” the agency stated. “But the pace of change remains too slow in regions most in need of affordable and reliable power.” China alone is expected to account for over one-third of global electricity demand growth through 2026, followed by India and Southeast Asia. However, the IEA highlighted that Africa, home to nearly 600mn people without access to electricity, continues to face chronic underinvestment in power infrastructure. “Sub-Saharan Africa is the only region where electricity demand is expected to remain below pre-pandemic levels in 2026,” the IEA warned. “This underlines the urgent need for greater international support.” The agency also noted that extreme weather events—linked to climate change—have added volatility to power markets. “Heatwaves, droughts, and cold snaps are creating new operational challenges for grids, especially where backup generation is limited,” the report said. In advanced economies, electrification of transport, heating and industry is expected to continue driving demand, though energy efficiency gains and economic uncertainty may limit overall growth. Europe, in particular, is expected to see relatively flat electricity demand due to high prices and slower industrial activity. To meet rising global demand and decarbonisation targets, the IEA estimates that annual investment in electricity networks must increase by more than 50% by 2030, reaching nearly $600bn globally per year. “Without faster grid expansion and stronger investment in emerging markets, the global energy transition risks becoming a tale of two worlds,” the agency concluded.

The Trans-Saharan Gas Pipeline (TSGP) project is making steady progress after Algeria, Nigeria and Niger reaffirmed their commitment to the 2024 agreements and are accelerating construction. The three countries endorsed updates to the project’s feasibility study by UK engineering consultancy Penspen, alongside a new compensation agreement and a confidentiality pact at a recent meeting in Algiers. The agreements mark a renewed push to complete the 4,128 km pipeline, which is designed to transport up to 30bn cubic metres of natural gas annually from Nigeria to Algeria’s Mediterranean coast for export to European and global markets. “The Trans-Saharan Gas Pipeline project is moving forward steadily,” officials from the Algerian Ministry of Energy and Mines said in a joint statement after the meeting. The TSGP, first conceived in the early 2000s, is aimed at replacing some of the Russian gas which is no longer being sold to Europe. It will bolster energy cooperation in West and North Africa and provide an alternative supply route to Europe, which intends to ban Russian gas imports next year as part of the nineteenth sanctions package. Once completed, the pipeline will connect Nigeria’s vast gas reserves to Algeria’s pipeline network, enabling onward delivery through the Trans-Mediterranean and Medgaz pipelines. According to project backers, about 60% of the TSGP’s route has already been completed, with approximately 2,400 km of pipeline laid, primarily in Algeria and Nigeria. The remaining 1,800 km will be constructed across all three partner countries, traversing difficult terrain including the Sahara Desert and regions with security challenges. The pipeline’s projected capacity of 30bn cubic metres per year represents a significant addition to regional and international supply, at a time when European demand for diversified gas sources remains high following the sharp reduction of Russian pipeline imports. At the same time, the EU has woken up to is dependency on American LNG and is seeking to diversify away from and increasingly unpredictable White House. Algeria’s national energy company Sonatrach, the Nigerian National Petroleum Company (NNPC), and Niger’s Ministry of Petroleum are jointly managing the development phase. Technical, financial and environmental updates are ongoing as part of a revised roadmap. Industry analysts say the project, if realised, could transform West Africa’s gas export profile. However, the TSGP has faced repeated delays due to financing hurdles, regional instability, and shifting global gas market dynamics.

A projected tenfold increase in India’s nuclear power capacity by 2047 is poised to upend the uranium market, creating a long-term supply-demand imbalance that analysts say the current production system is ill-equipped to manage. India has set a target to boost its nuclear generation capacity from the current 7.5 gigawatts to 100 gigawatts by 2047, according to the Department of Atomic Energy. Meeting that goal would add approximately 23mn kilos of annual uranium demand—equivalent to around 30% of global uranium production today, based on World Nuclear Association data. “This creates a projected cumulative deficit of 770,000kg … nearly 10 times current annual uranium production,” industry analyst Lukas Ekwueme said. “The uranium supply–demand model is broken.” The forecast shortfall reflects a confluence of rising demand and constrained supply. India is not alone in turning to nuclear power to meet decarbonisation goals. China has emerged as the world's leading builder of nuclear power plants, completing new reactors in as little as five years and currently has around 30 nuclear power plants (NPPs) under construction. Russia is also massively expanding its NPP fleet and nuclear exports are booming with three dozen international projects on the state-owned Rosatom’s docket. Several European nations are also planning to expand or extend their nuclear fleets. The International Energy Agency (IEA) expects global nuclear capacity to increase by more than 40% by 2050 under its stated policy scenario. However, global uranium supply is under pressure. While several countries mine uranium, including Kazakhstan, Uzbekistan, Canada and Niger, enriching the ore remains dominated by Russia. But several major global mines remain shuttered following a prolonged bear market after the Fukushima disaster in 2011. While prices have rebounded sharply—spot uranium surpassed $220 per kilogram ($100 per pound) in January for the first time since 2007—project development has lagged. Kazakhstan, the world’s largest uranium producer, has faced production challenges due to wellfield constraints and limited access to sulphuric acid, a key input. Canada’s Cameco has also cited labour shortages and technical difficulties at its flagship operations. “There is no quick fix,” said Ekwueme. “It takes years to bring a uranium mine online, and few producers have the balance sheets or regulatory certainty to make the leap today.” India’s ambitious nuclear programme is part of a broader push to reduce dependence on coal and imported fossil fuels. With more than 70% of its electricity still generated from coal, Delhi aims to decarbonise while supporting its rapidly growing population and industrial base. Yet India currently imports all its uranium, relying primarily on suppliers in Kazakhstan, Canada, and Uzbekistan. Supply security could emerge as a strategic concern in the coming decades, particularly as Western utilities compete for the same barrels in an increasingly tight market. The biggest uranium producer Kazakhstan is seeing a production peak. It produces about 40% of the global uranium supply, but by 2046, production from existing mines will decline by 80%, say analysts. Given it usually takes about 20 years from exploration to first production, there is likely to be a supply short fall unless billions are spent on exploration just to offset Kazakhstan’s decline curve. However, President Vladimir Putin claims Russia has a solution. He announced in September Russia has made a nuclear technology breakthrough and has developed a closed fuel cycle power system to tackle global uranium shortages. Russia is moving ahead with the development of its first industrial-scale closed fuel cycle reactor, the BREST-OD-300, which would be a gamechanger if the claims are confirmed. A closed fuel cycle reactor is a fuel management strategy, not a specific reactor type. Spent nuclear fuel is reprocessed and reused, rather than being treated as waste after one use, as in an open fuel cycle. The BREST-OD-300 recycles fuel on-site, enabling continuous reuse of uranium and plutonium. The reactor is similar to a fast breeder reactor that uses fast neutrons, unlike conventional reactors, and is specifically designed to "breed" more fissile material than it consumes. China also claims that it has cracked the problem of fusion reactors which would also solve the fuel problem. The Shanghai-based commercial fusion energy company Energy Singularity announced on June 19 that it has successfully built the world’s first fusion reactor that puts out more energy than it takes in to run it, The Global Times reported.

Atlantic LNG is expected to take Train 4 offline for up to 50 days in May and June to complete repair work, Reuters reported on February 6, citing sources with knowledge of the matter. Train 4 at Trinidad and Tobago’s flagship LNG facility has a production capacity of 6mn tonnes per year (tpy). It marks the second announcement in consecutive months by Atlantic LNG of taking offline liquefaction units at the facility. In late January, Atlantic LNG’s director for capital projects Michael Daniel stated at the Trinidad and Tobago Energy Conference that the plant would shut down Train 1 later this year in the fourth quarter. Daniel said that the decision was made due to a shortfall of feed gas, while acknowledging that the train has not been producing LNG for over a year. Nevertheless, the liquefaction unit has remained in operation the entire time because the utilities, including the electricity that powers all four trains, are in Train 1. The rest of the plant’s operations are not expected to be impacted by the decommissioning of Train 1. Meanwhile on Train 4 the maintenance and repair work is expected to last between 45 and 50 days. The facility will still produce the super-chilled fuel from Trains 2 and 3, which together combine for a production capacity of 6mn tpy. However, officials stopped short of saying Trains 2 and 3 would still operate at full capacity during the period. Atlantic LNG is the biggest export terminal in Latin America with a nameplate capacity of 12mn tpy. However, the facility has been hamstrung by a lack of feed gas and in 2025 produced only 9mn tonnes of the super-cooled gas. Supermajors Shell (SHEL) and BP (BP) are the majority owners of Atlantic LNG with both holding stakes of 45% while Trinidad’s National Gas Company holds the remaining 10% interest.

Taiwan has confirmed it will increase US LNG imports to comprise about one-third of its imported supply of the super-chilled fuel in 2026, officials stated on February 5 Reuters reported. The announcement comes as Taiwan seeks to avoid tariffs being applied from the US. The island possesses a significant trade surplus with Washington and has expressed interest for almost a year in the US’s megaproject in Alaska. US imports of Taiwanese products hit a record high of $111bn in 2024 as demand skyrocketed for Taiwan’s high-tech products, especially semiconductors. "We plan to increase purchases of natural gas from the U.S. to 30%-33% this year from about 10% now," Chairman of Taiwan’s state-run CPC Corp, Fang Jeng-zen said. With Taiwan set to significantly ramp-up imports of LNG from the US, the world’s second and third largest exporters Qatar and Australia are likely to see a major reduction in the sales to the island. Data from Kpler revealed that in 2025, the two countries each supplied about 23.8mn tonnes of the super-cooled gas, making each country responsible for about one-third of Taiwan’s supply. For Australia, this will mark a further decline in its share of Taiwan’s LNG imports after its share also fell in 2025 to 33.4%, For Qatar, it will mark a change in direction as the Gulf nation had previously been seeing a rise in the share of Taiwan’s LNG imports that it supplied, climbing from 25% in 2021 to 33.5% in 2025. The US has been aggressively courting energy-hungry trade partners in East Asia, including Japan and South Korea, in addition to Taiwan, to agree to import the super-chilled fuel from Glenfarne’s Alaska LNG. With a price tag of $44bn, the US is desperate to lock in buyers for the megaproject. In September, Japan’s JERA signed a preliminary deal to buy LNG. One month later, Tokyo Gas also inked a letter of intent. Additionally, Thailand’s state-owned oil and gas company PTT has also agreed to a preliminary deal.

Shell has paused investment in Kazakhstan amid wrangling between oil majors and the oil-rich Central Asian nation over legal claims that could cost the companies billions of dollars. As reported by Bloomberg on February 5, Shell (LON: SHEL) chief executive officer Wael Sawan, referring to the compensation demands, told analysts during an earnings call: “It does impact our appetite to invest further in Kazakhstan.” Sawan was further reported as saying that while Shell sees plenty of future investment opportunities in Kazakhstan, “we will hold until we have a better line of sight to where things end up”. Kazakhstan, an OPEC+ country, has launched multiple court and international arbitration cases against Western oil companies. In late January, it emerged that Shell, Eni (BIT: ENI) and other partners had lost an arbitration case over matters including claimed unapproved and non-reimbursable expenses at the Karachaganak gas condensate field in northwestern Kazakhstan brought by the Kazakh government. The outcome could mean they are on the hook for as much as $4bn in compensation. The case is said to have heard that Kazakh officials allegedly accepted bribes to sign off on billions of dollars of costs claimed by shareholder companies in Karachaganak and that Kazakhstan had admitted that it had tolerated “corruption and kleptocracy” related to the field until 2022. Other disputes relate to sulfur handling. Bloomberg said that it remained unclear whether the pause announced by Sawan related only to new investments or also affected existing projects. Other partners in the Karachaganak consortium include Chevron Corp (NYSE: CVX), Lukoil (MCX: LKOH) and national oil company KazMunayGas (KZ.KMGZ). The venture may still appeal the arbitration decision. Kazakh analysts have described Kazakhstan’s victory in the Karachaganak case as significantly strengthening its position in other ongoing legal disputes, including those related to the massive offshore Kashagan oil field in the Caspian Sea, The Times of Central Asia reported on February 4. The publication referred to how during the arbitration, Kazakhstan’s legal team put forward documents from criminal proceedings in Italy that revealed that, in 2017, several Italian contractors pleaded guilty to bribing Kazakh officials in order to obtain Karachaganak and Kashagan contracts. Oil and gas analyst Olzhas Baidildinov was cited by the media outlet as saying that the ruling gives Kazakhstan greater leverage in negotiations and litigation over large energy projects. He noted that the country can now “firmly defend its rights in major oil and gas projects,”, with the longstanding privileged position of foreign oil majors in Kazakhstan’s oil sector coming to an end. Baidildinov was reported as suggesting that the operating models at both Karachaganak and Kashagan may be restructured and potentially “de-Italianised”. He also criticised KazMunayGas for staying silent on the Tengizchevroil (TCO) expansion project at the Tengiz field, located along the shores of the Caspian Sea. Its capital expenditure has surged from $12bn to $48.5bn. The Times of Central Asia reported Baidildinov as drawing comparisons to Uzbekistan, noting that former Uzbekneftegaz head Bahodir Sidikov was dismissed in December before being detained on corruption charges, with presidential energy adviser Alisher Sultanov also removed. “I’m astonished that, while regional Kazakh officials are being arrested for bribes worth mere hundreds of thousands of tenge, we continue to accept the TCO budget of $48.5 billion without scrutiny,” Baidildinov told the publication, adding: “That’s 33 times the cost of the Burj Khalifa, six times the price of the Large Hadron Collider, and more than the infamous Kashagan offshore project, even though Tengiz is an onshore field with existing infrastructure.” Top figures at KazMunayGas overseeing Tengiz should be held accountable, said Baidildinov.

Serbia is stepping up efforts to diversify its energy supplies away from Russia and is already in talks to purchase natural gas through the European Union’s joint gas-buying mechanism, President Aleksandar Vucic said in an interview with Reuters on February 4. The Balkan country, which is seeking EU membership, remains one of Europe’s most energy-dependent states and among Europe’s few remaining buyers of Russian gas. More than 80% of Serbia’s gas supplies still come from Russia, but Brussels has been pressing Belgrade to find alternatives as the EU seeks to curb revenues flowing to Moscow amid the war in Ukraine. “We have to adjust our energy policies to certain demands and requests,” Vucic told Reuters during the interview at the presidency in Belgrade, where he was flanked by an EU flag. “Still we will have big quantities of Russian gas, but we are taking more and more from Europeans.” Serbia failed to secure a new long-term contract with Russia’s Gazprom last year, after Moscow declined to offer a multi-year deal in October 2025. A short-term agreement reached in December expires on March 31, leaving Belgrade reliant on temporary arrangements and Russia’s goodwill for access to relatively cheap gas. Vucic said Serbia is aiming to secure around 500mn cubic metres of gas per year – roughly one-fifth of its annual demand – through the EU’s communal gas-buying initiative, which it joined last year. The country is already importing gas from Azerbaijan via Bulgaria, while construction of a pipeline to North Macedonia, which would provide access to liquefied natural gas (LNG) terminals in Greece, is expected to start this year. An oil pipeline linking Serbia with neighbouring Romania is due for completion in 2027, while additional gas and oil connections with Hungary and Romania are also planned. “This is a big diversification,” Vucic said in the interview. Serbia imports nearly all of its gas – about 3bn cubic metres in 2024 – with domestic production covering only around 10% of needs. The government has launched a broader push to diversify gas and electricity supplies, expand renewable energy and attract foreign investment into energy infrastructure after years of underinvestment. By the end of 2026, Belgrade aims to secure 1.3 GW of new renewable capacity through competitive auctions, covering solar, wind and energy storage. Meanwhile, domestic coal reserves are at record levels, while state gas company Srbijagas plans to double storage capacity at the Banatski Dvor facility. Serbia is also reviving its nuclear ambitions. After lifting a decades-old ban in 2024, the government is exploring both large-scale nuclear plants and small modular reactors as part of its long-term energy strategy. With new pipelines, storage projects and renewables capacity in the pipeline, alongside plans to incorporate hydrogen and expand regional cooperation on energy infrastructure, Serbia’s shift away from near-total reliance on Russian energy is expected to open up fresh opportunities for foreign direct investment across the sector.

Europe’s dependence on liquefied natural gas (LNG) from the US and Russia surged to an all-time high in January, with the two countries accounting for more than 80% of the continent’s total seaborne imports, Bloomberg reported on February 5. According to data compiled by ship-tracking firm Kpler, the US supplied 55% of Europe’s LNG imports last month, while Russia contributed just over 25%. Europe imported a record 142bn cubic metres of liquefied natural gas in 2025, marking a 28% increase from the previous year. The figures mark a significant increase from a year earlier, when the combined share of the two exporters stood at roughly 70%. The shift comes as Europe intends to ban imports of Russian gas completely by January 1, 2027. However, Europe remains Russia’s biggest customer for LNG, accounting for half of Russia’s annual production. Almost all of Russia’s exports to Europe come from the Novatek Arctic LNG production. For its part, Europe remains hooked on Russian gas imports, despite efforts to scale back imports. At the same time, Europe has swapped its dependency on Russian gas imports for a dependency on American LNG imports. More recently, unsettled by the Trump administration’s Greenland annexation threats, the EU seeks to diversify away from US LNG dependency, but is struggling to find alternative supplies. Russia remained the fourth-largest supplier of natural gas to the EU in 2025, exporting nearly 38bn cubic metres despite ongoing efforts to cut imports. Imports have surged in recent months as a big freeze settles on the world, following the collapse of the polar vortex releasing icy air masses over northern countries and beyond. The EU has banned most Russian crude and petroleum product imports, but Russian LNG remains exempt from sanctions, allowing Moscow to maintain and even expand its market share in Europe’s gas sector. The growth in Russian LNG imports has drawn criticism from some EU member states and environmental groups, who argue that it undermines the bloc’s geopolitical and energy security goals. “We are replacing one form of Russian gas dependency with another,” said Anna Michalska, an energy analyst at the Centre for European Policy. “While LNG offers greater flexibility, the continued inflow from Russia highlights the lack of coherent long-term strategy.” LNG imports from the US have soared since 2022, supported by high European prices and Washington’s efforts to supply allies with alternatives to Russian energy. The rise has made the US the world’s largest LNG exporter, surpassing both Qatar and Australia in 2023. European buyers have remained active on the LNG spot market. Benchmark TTF gas futures fell nearly 60% in 2023, but forward contracts suggest buyers are hedging against potential supply disruptions or further geopolitical escalation. Kpler data show that France, Spain and the Netherlands were the largest importers of Russian LNG in January, while major volumes of US cargoes were delivered to terminals in the UK, Belgium and Germany. “We are focused on diversifying supply and strengthening our resilience,” a European Commission spokesperson said, but declined to comment directly on the rising share of Russian LNG.

The Angola Oil & Gas 2026 conference (AOG), now entering its seventh edition, is scheduled to take place in September in Luanda, bringing together government leaders, international and local operators, financiers and service companies. The 2026 conference is positioned as a catalyst for up to $70bn in investment across the upstream value chain, which will help to translate Angola’s licensing success into deliverable projects, the African Energy Chamber (AEC) said in a press release. According to the AEC, independent oil and gas companies are becoming more active in Angola’s onshore basins, especially Kwanza and Congo, as they run seismic surveys, build acreage positions and prepare for drilling that could add new reserves and extend the life of the country’s hydrocarbons sector. “After decades defined by deepwater success, Angola’s upstream sector is rediscovering its onshore potential. Previously overshadowed by prolific offshore blocks, the country’s inland basins are re-emerging as a strategic frontier – not led by supermajors, but by independent oil and gas companies willing to take early-stage risk in pursuit of long-term value,” the AEC noted. One of the most active new entrants is Nigerian energy company Oando (NGX:OANDO), an integrated oil and gas group, which entered Angola’s upstream sector in early 2025 as the operator of Block KON 13 in the onshore Kwanza Basin, holding a 45% stake. The block is being developed as a long-term exploration play linked to offshore geological analogues. UK-based junior explorer Corcel (AIM:CRCL) has consolidated just over 70% of Block KON 16, alongside partners including Canadian upstream investor Sintana Energy (TSXV:SEI). According to the AEC, Corcel is progressing technical studies and seismic work ahead of drilling planned for 2026. Canada-listed ReconAfrica (TSXV:RECO), a frontier basin explorer, has also secured access to large inland areas under an agreement with Angola’s regulator ANPG. Local firms Etu Energias and Alfort Petroleum are advancing seismic interpretation, with Alfort planning a well proposal for Block KON 8 in 2026. Angola has drawn more independent investment inland by reforming its licensing and regulatory framework. As the AEC points out, since launching a multi-year licensing round in 2019, the government has regularly awarded new onshore and offshore concessions, reducing uncertainty and giving companies greater visibility to plan exploration over the medium term. In parallel, Angola introduced a permanent offer regime, which allows firms to negotiate access to open blocks outside formal bidding rounds. This has been especially appealing to independents, as it offers flexibility and faster market entry. Together with risk service contracts and marginal field frameworks, these measures provide several pathways for companies with different funding capacities and risk profiles to invest in Angola’s onshore sector. According to AEC’s executive chairman NJ Ayuk, these policy tools will facilitate industry dialogue at the AOG 2026 conference, which has become a central platform for advancing the country’s onshore ambitions. “By spotlighting onshore basins alongside offshore developments, AOG provides a forum for independents to showcase progress, secure partnerships and align with Angola’s long-term energy strategy,” says Ayuk. “As the country looks to sustain production and attract diversified capital, the return to onshore – led by agile, exploration-focused companies – is becoming an increasingly important part of the narrative. In this new chapter, Angola’s inland basins are no longer a legacy asset, but a frontier once again shaping the future of its oil and gas industry.”

Equatorial Guinea has taken a major step to strengthen its gas sector by signing a new financing agreement for the Aseng Gas Project, the African Energy Chamber (AEC) said in a media release on February 2. The Ministry of Hydrocarbons and Mining Development and US supermajor Chevron (NYSE:CVX) have signed a Heads of Agreement (HoA) that supports greater state participation through the national oil company (NOC) GEPetrol. The deal focuses on funding GEPetrol’s expanded role in the project and speeding up development across the country’s wider Gas Mega Hub strategy. Under the agreement, GEPetrol will raise its stake in the Aseng Gas Project from 5% to 32.55%. This gives the state a much stronger position in managing and benefiting from its natural gas resources. The gas produced from Aseng will not only support the field itself but will also help to unlock a range of related projects. These projects comprise new upstream and downstream developments, including the Alen Tail and Yoyo-Yolanda projects, additional drilling in Chevron-operated blocks, and potential cross-border gas flows using existing Gulf of Guinea pipeline systems. “In this context, the HoA functions as an enabler, unlocking a portfolio of projects rather than advancing a single field,” says the AEC. A key benefit of the deal is the long-term supply of gas to the Punta Europa industrial complex. This allows Equatorial Guinea to make better use of its existing LNG and gas processing facilities. Using current infrastructure lowers costs, reduces the risk of gas being left undeveloped, and improves the country’s position as a regional gas hub at a time when flexible LNG supply is increasingly important. “This agreement represents a strategic step forward for our energy sector, enhancing national participation and opening the door for further projects that will drive industrial development, create jobs and strengthen energy security for our country and the region,” said Antonio Oburu Ondo, Minister of Hydrocarbons and Mining Development of Equatorial Guinea. According to the AEC, the HoA sends a clear signal on Equatorial Guinea’s policy direction to investors. It shows strong coordination between the state, the NOC and a major international operator, as well as a willingness to use flexible financing to move projects forward. “As global gas markets prioritise reliability, infrastructure access and regional integration, Equatorial Guinea’s approach positions it as a stabilising supplier in the Gulf of Guinea,” the AEC said in the statement. “The Aseng HoA does not merely strengthen GEPetrol’s balance sheet position; it reinforces the country’s ability to convert gas resources into industrial growth, export capacity and cross-border energy cooperation.” Equatorial Guinea, OPEC’s smallest member, has been an LNG exporter for almost 20 years. The Aseng project is operated by Chevron, with partners GEPetrol, global commodities producer and trader Glencore (LSE:GLEN) and Switzerland-based private energy trading company Gunvor Group.