In the few days since that dramatic raid, the narrative in Washington has changed with Trump stating publicly that the United States intends to run Venezuela and take direct control of Venezuelan oil exports and revenue “indefinitely.” During a January 9 meeting with CEOs and senior executives of U.S. and international oil companies, Trump said Venezuela would hand over 50 million barrels of its crude to be refined or marketed by the United States “immediately.” This might have an impact on near-term oil supplies at a time when the market is well supplied, though much of the extra heavy Venezuelan oil is likely to be taken by U.S. refineries for blending with the lighter grades produced domestically. “We have the refining capacity – was actually based very much on the Venezuelan oil, which is a heavy oil, very good oil, great oil,” Trump said during the televised meeting. He also urged the international oil companies to help rehabilitate the Venezuelan oil industry that he said had been mismanaged and would require $100 billion in investments to achieve its true potential.

Global oil prices did not react to the developments in Venezuela. There might be longer term implications for supply, but few experts expect an immediate surge in Venezuelan oil production given the dilapidated state of the Venezuelan oil industry’s infrastructure, the need for a new fiscal regime and hydrocarbon law, and concerns about continued insecurity – issues raised by some executives during the meeting at the White House. Brent crude oil was trading between $61 per barrel and $63/bbl, roughly at the same level at the close of business in December 2025, in the days following the intervention in Venezuela. They rose sharply on January 13 to trade above $65/bbl on market fears of disruption to Iranian oil supplies amid a wave of nationwide protests that began at the end of December.

From a narrow market perspective, the implications for OPEC are modest in the short term. Venezuela’s output, hovering just below 1 million barrels per day (around 1% of global supply), remains far below its late-1990s peak of nearly 3.5 mb/d. This is a fraction of what the country could produce given its massive resource base, estimated at 303 billion barrels, the largest in the world, though not all of it is commercially viable. On paper, Venezuela’s oil reserves exceed Saudi Arabia’s 267 billion barrels, but Saudi Arabia has capacity to produce more than 10 times as much oil as Venezuela thanks to a stable government and a well-run state oil company in Saudi Aramco. The United States, with 44 billion barrels of reserves, is today the world’s largest oil producer due to the surge in shale oil production that allowed it to overtake Saudi Arabia and Russia, with current U.S. oil production estimated at over 20 mb/d.

In Venezuela, decades of underinvestment, infrastructure decay, and institutional collapse at state oil company Petróleos de Venezuela, known as PDVSA, as well as more recent U.S. sanctions mean that even under optimistic assumptions production growth would be slow, capital intensive, and measured in years rather than months. This helps explain why oil prices have remained relatively calm, despite the geopolitical drama, and why OPEC has made no official comment on the developments.

What matters for OPEC, and for the market, is not reserves in the ground but barrels that can be produced and marketed effectively. Venezuela has had to rely on oil swaps with Iran, another OPEC member struggling with a collapsing economy due to sanctions, and on China, which receives some Venezuelan oil as debt repayment.

As one of OPEC’s five founding members at a time when its production was on the rise, Venezuela was able to shape policy decisions within the group. That influence waned after the late Hugo Chavez took over management of the oil sector from PDVSA, firing hundreds of employees and squeezing the oil giant’s revenue to fund his populist agenda as Venezuela’s president. Production plummeted further after a 2002-03 strike by PDVSA oil workers crippled the industry. Oil production fell below 500,000 b/d, and exports were severely disrupted. Thousands of employees were fired or left the country. Even after production recovered in subsequent years, the industry never regained its prestrike technical depth, as the government’s take increased.

In 2007, Chavez expelled major U.S. oil companies, including ExxonMobil and ConocoPhillips, and seized their assets, for which the companies are still awaiting billions of dollars in compensation. Chevron was the only major U.S. oil company that stayed, operating under a special U.S. license, and could ramp up production in the short term.

While major oil companies often operate in risky environments, they require guarantees of returns on their investments in a stable fiscal environment. Both ExxonMobil and Chevron are considering investments in Iraq’s energy sector, which also faces an unpredictable political future given the current postelection paralysis but provides lower cost and higher quality crude than Venezuela’s extra heavy oil.

Tackling methane emissions from Venezuela’s oil and gas operations would be an additional cost to any potential investor. The International Energy Agency noted in the “Latin America Energy Outlook 2023” that “the methane emissions intensity of oil and gas operations in Venezuela is five-times the world average, and their flaring intensity is over seven-times higher the global average.” Although the environmental impact of methane emissions may not be of much concern to the current U.S. administration, it is relevant to the multinational oil companies. At the December 2023 COP28 climate summit in Dubai more than 50 oil and gas companies, including the U.S. majors, pledged to reduce methane emissions from their operations to near zero by 2030. Methane is a powerful greenhouse gas that traps heat close to the earth’s surface. Venezuela is not a signatory to the Global Methane Pledge.

ExxonMobil’s CEO, Darren Woods, was virtually alone among the executives to argue that Venezuela was not currently an attractive investment prospect. He told the U.S. president, “We first got into Venezuela back in 1940s. We’ve had our assets seized there twice. And so, you can imagine to re-enter a third time would require some pretty significant changes from what we’ve historically seen here … If we look at the legal and commercial constructs – frameworks – in place today in Venezuela, today it’s uninvestable. And so significant changes have to be made,” including to the country’s hydrocarbon law and its legal system, he added.

For decades prior to the Chavez presidency, PDVSA acted as a state within a state, with the head of the company enjoying greater power than the minister of energy. Such was PDVSA’s influence that one minister had compared it to “an elephant in a swimming pool” because of the ripple effect its decisions had on the country’s economy, according to a section in the book “Oil Leaders” by former senior Saudi oil advisor Ibrahim AlMuhanna.

As its oil production slumped so did Venezuela’s influence in OPEC. Today, effective market management rests with the Gulf states – led by Saudi Arabia and the United Arab Emirates – alongside Russia within the OPEC+ alliance. That concentration of influence has delivered stability, but it also means Arab producers are acutely sensitive to any precedent that weakens producer sovereignty or normalizes external intervention in oil-exporting states.

Another dimension that matters for the Middle East is the question of influence within OPEC and OPEC+. With the United States now asserting de facto control over Venezuelan oil sales and revenue, will that translate into indirect influence on OPEC or OPEC+ deliberations? Could the United States eventually push for Venezuela’s withdrawal from the organization? It is far too early to answer these questions, but they are ones that Gulf producers and other members will no doubt be discussing behind closed doors.

At present, Venezuela is exempt from OPEC+ output quotas, and the United States would certainly not allow production to be dictated by the Saudi- and Russian-led alliance even if production were to increase. There is a consensus among experts that it will take years or even decades to restore Venezuelan production beyond the 2025 average of 930,000 b/d.

Ivan Sandrea, a Venezuelan energy expert and a former head of oil supply at OPEC, wrote in a LinkedIn post that he had reviewed crude oil production data from Iran, Iraq, Algeria, Libya, and Venezuela – all members of OPEC – over 1970-75 and examined how long it took each to recover peak production. All five have suffered from output declines either because of geology, lack of investment in new capacity, internal strife, or sanctions. He noted that the period was chosen specifically because “it marked the peak of Venezuelan production, preceded the Iranian Revolution, and came before major regime change, conflict, and structural disruption across several OPEC producers.” (It was also during this period that OPEC wielded its oil weapon with the 1973 oil embargo, which led to the rise of North Sea oil and a U.S. quest for energy independence at a time when the Middle East was one of its biggest suppliers.)

In an accompanying chart, Sandrea showed that recovery is generally slow, uneven, and rarely linear, and that geology is not the primary constraint. Iran, Libya, and Algeria needed 20 years to recover production, while Iran and Venezuela never fully recovered. Iran produced 3.3 mb/d of crude oil in November 2025, according to secondary source estimates cited by OPEC, which is roughly half what it produced at its peak in the mid-1970s and far below current capacity.

Sandrea pointed out that Venezuela is the most extreme case with production today at 20% of its peak level. This, he wrote, reflects “profound destruction of capacity rather than resource depletion.” Iraq, by contrast, managed to restore and significantly expand production within roughly a decade following the ouster of Saddam Hussein in 2003. “For Venezuela, the challenge – and the opportunity – is clear,” he wrote, adding that it would likely take more than 10 years to restore production in Venezuela, assuming discipline and sustained execution. “Expectations of a rapid production surge should therefore be tempered accordingly.”

The U.S. Energy Information Administration admitted as such in a February 2024 analysis of Venezuela’s oil sector. In the report, the EIA estimated that Venezuela’s total energy production declined by an average 8.2% between 2011 and 2021 due to what it said was “government mismanagement, international sanctions, and the country’s economic crisis.” As a result, it expects crude oil output growth to be limited even after the lifting of U.S. sanctions.

Should U.S. firms return to Venezuela, they would find a sector hollowed out by years of underinvestment, operational decay, and institutional dysfunction. For OPEC’s Middle Eastern core, the significance of Venezuela’s upheaval lies less in near-term supply than in the precedent it sets. A founding member of the organization is now effectively under external control, raising questions about sovereignty, influence, and the resilience of producer-led market management.

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While both parties signed a Joint Declaration on the Completion of Negotiations on Civil Nuclear Energy Cooperation, this document further underscores what has yet to be agreed upon: the issue of domestic enrichment and the transfer of sensitive technology and know-how. After years of negotiations, it had looked like Mohammed bin Salman’s visit might have culminated in a 123 agreement, the legally required framework under the United States’ 1954 Atomic Energy Act for the transfer of nuclear materials, technology, and knowledge.

In an interview, U.S. Energy Secretary Chris Wright indicated that the cooperation being discussed is “not about enrichment. It’s not about anything related to weapons.” However, importantly, uranium enrichment does not equate to nuclear proliferation: While nuclear enrichment and reprocessing are the two pathways for acquiring the bomb, all parties to the Nuclear Nonproliferation Treaty, including Saudi Arabia, have the right to pursue such capabilities for civilian purposes under International Atomic Energy Agency safeguards. Second, Wright’s statements indicate that the enrichment question for Saudi Arabia has yet to be settled. Therefore, while the joint declaration cements U.S. interest in nuclear cooperation with the Saudis, the road ahead remains long. For the time being, the joint declaration acts as a placeholder, leaving the door open for further negotiations, which could culminate in a 123 agreement that satisfies both parties.

Saudi Arabia’s Nuclear Reasoning

Under Vision 2030, the kingdom aims to diversify its energy mix, develop domestic industries, and reduce its dependence on foreign expertise. Nuclear energy fits in that strategy, as it would free up more oil for exportation, helping to finance megaprojects in the country. At the same time, it would provide a stable, nonfossil fuel source to meet domestic electricity demands. Further, the skills acquired in the hydrocarbon sector, already mastered in the kingdom, could also be transferred to the nuclear industry in some respects. Therefore, provided that the Saudis find a supplier that would share sensitive technology and know-how, and allow them to enrich uranium domestically, Saudi Arabia could theoretically develop new types of services in the nuclear industry. The kingdom’s uranium ore reserves (an estimated 90,000 metric tons), while insufficient for exportation, would suffice for domestic use, ultimately enabling the Saudis to develop a fully indigenous and independent nuclear fuel cycle. Such autonomy could down the line enable Riyadh to hedge capabilities as part of an overall defense strategy.

Saudi Arabia is unlikely to let go of this capability for a variety of reasons revolving around pride, national interest, and sovereignty. Given its inherent right to enrich under the Nuclear Nonproliferation Treaty, and its substantial uranium deposits, Riyadh sees no reason to constrain itself by forgoing enrichment and signing a more restrictive, “gold standard” 123 agreement, like the one agreed to by the United Arab Emirates, especially when other U.S. partners, such as South Korea, were not required to do so. (Although South Korea notionally retained the right to domestic enrichment, with U.S. permission, the United States withheld consent for more than 20 years, only agreeing to it during Trump’s recent visit. While the U.S.-UAE 123 agreement is believed to be the “gold-standard” of nonproliferation, the kingdom seems to understand it as a voluntary exception that must not become the rule in the region. Already, Saudi Arabia, like Egypt, has suggested that Arab states have been subjected to double standards by the nonproliferation community, which relied on strategic ambiguity to tacitly allow for a nuclear Israel and permitted an Iranian enrichment program under the Joint Comprehensive Plan of Action nuclear deal. Meanwhile, Arab states have been expected to forgo enrichment and subject themselves to the IAEA Additional Protocol, a voluntary safeguard agreement that provides the agency with a broader array of access and information.

While the conclusion of the Comprehensive Safeguards Agreement (a mandatory safeguards agreement for all nonnuclear weapons states party to the Nuclear Nonproliferation Treaty) with the IAEA is required by the 123 agreement, there is no explicit mention of the Additional Protocol in the U.S. agreement. The UAE is the only state to have signed and ratified the Additional Protocol under its 123 agreement. Any 123 agreement must meet nine nonproliferation requirements, namely the need to “obtain approval before enriching or reprocessing transferred nuclear material.” Typically, once signed, the 123 agreement is submitted to Congress, which has 90 days to review it. To block such an agreement, a joint resolution of disapproval would have to be adopted with a “supermajority,” ensuring that the presidential veto doesn’t override it, which has been historically difficult to achieve.

Finally, even though no 123 agreement came out of Mohammed bin Salman’s trip, Saudi leaders understand that if they want nuclear cooperation with Washington, their best option is to secure it while Trump is in power, given the intricate ties between the Saudi royal family and the president’s circle. Trump has also made it a priority since the beginning of his second term to revitalize the U.S. nuclear industry, as Russia and China account for the majority of planned nuclear reactors internationally. A multibillion-dollar nuclear partnership with Saudi Arabia could revitalize companies such as Westinghouse and Bechtel while avoiding Chinese involvement in the Saudi nuclear program. Removing the question of Saudi Arabia normalizing ties with Israel from the nuclear equation, and avoiding restrictive language that could alienate Riyadh, like “gold standard,” during Mohammed bin Salman’s trip underscores the U.S. administration’s interest in bringing an agreement to life.

Both sides have therefore incentives to keep the door open for negotiations, and many possibilities lie ahead, including:

1. An iron-clad defense treaty and a gold standard compromise: Although Saudi Arabia has been elevated to the status of non-NATO ally, it is hard to imagine the kingdom under a U.S. nuclear umbrella. However, it seems to be the only case in which the kingdom might agree to forgo enrichment capabilities. Such a security agreement, ratified by Congress, would diminish the kingdom’s need to hedge through domestic enrichment. That said, Saudi Arabia’s trust in U.S. security guarantees remains tainted by Washington’s lack of response to the 2019 attacks on Saudi oil facilities in Abqaiq and Khurais. In addition, enrichment is not merely part of a hedging strategy; it symbolizes the kingdom’s sovereignty and self-sufficiency. Thus, even under such a treaty, Riyadh could still demand domestic enrichment rights.
2. An ambiguous 123 agreement: Given the manner in which the joint declaration has been framed, the most plausible scenario would be one in which the 123 agreement signed would neither authorize nor explicitly ban Saudi enrichment. It would leave the door open for future negotiations while allowing both parties to move forward with the construction of nuclear power plants. That way, as trust incrementally builds, Saudi considerations could be framed under a review mechanism, establishing a temporary moratorium on enrichment that would be revisited every couple of years.

   While the agreement would probably ban reprocessing and the storage of spent fuel, the Saudis would still gain significant technical experience and develop workforce capabilities. A parallel can be drawn with South Korea, which recently secured U.S. support to revisit its right to enrich and reprocess uranium under its 123 agreement.

   However, if Saudi Arabia is provided with anything less than a “gold standard,” the UAE has the right to renegotiate the terms of its deal under the “most-favored nation” clause of the U.S.-UAE 123 agreement. Although it is unlikely for Abu Dhabi to demand equal enrichment rights because it has neither the ambition nor the capability to maintain a domestic nuclear fuel cycle, it could use it as leverage to try to push through its long-awaited F-35 purchase or in other negotiations with the United States.

   This agreement would ensure Saudi Arabia does not develop a nuclear program with a more permissive supplier, such as China, and provide sufficient ambiguity to avoid having Iran use it as an argument during its future negotiations with the United States on its nuclear program.

3. Saudi Arabia is granted its enrichment wish: The United States could end up authorizing the Saudis to enrich uranium to avoid Chinese-Saudi nuclear cooperation. Beijing is already collaborating with Riyadh on uranium extraction from seawater and a yellowcake extraction facility. With China’s help, Saudi Arabia is also believed to be building a ballistic missile facility. China, historically more flexible on the issue than the United States, could allow for enrichment and transfer of know-how, enabling a fully indigenous Saudi nuclear fuel cycle.

   Granting Saudi Arabia its enrichment demand could present the opportunity to cap both Iran’s and Saudi Arabia’s enrichment levels at 3.67% (the level of enrichment previously granted to Iran under the JCPOA) and enforce the ratification of the Additional Protocol, allowing the IAEA deeper oversight of their respective activities. Iran has signaled its willingness to restart negotiations with the United States, and Saudi Arabia has long asked for equal capabilities as its neighbor. Despite turbulence in the region, the relationship between these historical rivals has remained stable since the China-brokered rapprochement in 2023. There could be a window to bridge the divide and push for a regional nuclear consortium.

4. No Agreement: It is also plausible that the joint declaration was signed to save face and serves more as a diplomatic placeholder than a pathway toward deeper cooperation. After almost a decade of negotiations, perhaps both parties have come to the realization that their interests in the area do not align. This way, both sides walk away claiming partial success: The United States for maintaining nonproliferation principles and Saudi Arabia for refusing to submit itself to double standards.

While neither side has indicated a timeline for signing the 123 agreement, they both seem to have approached the issue with pragmatism through a joint declaration focusing on converging factors, including the transfer of technologies, rather than on divisive topics, namely enrichment.

The post As the Spotlight Fades: Where Is U.S.-Saudi Nuclear Cooperation Headed? appeared first on AGSI.

Several analysts and much of the media interpreted the Current Policies Scenario as a reversal of the IEA’s earlier projection under a different scenario showing a peak in demand for oil and gas by the end of the decade. But that is not an accurate comparison, because the Current Policies Scenario has not been included in the outlook since 2019. It was resurrected this year under pressure from Washington, which has criticized the IEA and its executive director, Fatih Birol, over what the administration of President Donald J. Trump perceives as an anti-fossil fuel stance at odds with the IEA’s mandate.

The IEA sees global energy demand rising by 32% from current levels by 2050 under all three scenarios, but the share of oil in each of the three varies greatly. Under current policy frameworks, oil demand would rise to 113 million barrels per day by 2050 from an average 100 mb/d in 2024, driven by demand mainly from emerging markets and developing economies for road transportation, petrochemicals feedstock, and aviation. Gas consumption would continue to grow into the 2030s.

The Current Policies Scenario assumes that governments will maintain policies already in place without change. This is not likely, as the energy landscape has evolved since 2019, when electric vehicle penetration was minimal and electrification of other sectors had not made a large dent in oil demand growth. A more accurate comparison would be with the previous Current Policies Scenario, when the IEA had projected oil demand rising to 121 mb/d by 2040. This year’s Current Policies Scenario therefore represents a significant downward revision of oil demand and shows the impact of the clean transition on the global energy mix in the last six years.

The scenario in the 2025 outlook takes what the IEA called “a cautious perspective on the speed at which new energy technologies are deployed and integrated into the energy system.” In this respect, it reflects a sense of pragmatism and realism given the rollback of some climate policies not only by the United States but also by the European Union, which also watered down some of its targets ahead of COP30.

Climate Change Commitments Falter

Birol, in presenting the report on November 12, admitted that “the priority given to climate change … at national and international level is in a decline in most cases.” At the same time, he noted that 2024 was the “hottest year in history,” and each of the scenarios would have implications for global greenhouse gas emissions and planetary warming.

In the Current Policies Scenario, in which consumption of oil remains on an upward trajectory, global temperatures would exceed 2 degrees Celsius by 2050, reach 2.9 C by 2100, and keep rising.

In contrast, the IEA’s Stated Policies Scenario, which assumes governments will implement some but not all announced plans, would see fossil fuel use peaking before 2030. Oil demand would remain flat over the next decade before falling to 96.9 mb/d 2050. Yet even in this scenario, the world would still miss the Paris Agreement climate goals of keeping “the increase in the global average temperature to well below 2°C above preindustrial levels” and “to limit the temperature increase to 1.5°C above pre-industrial levels.” The Stated Policies Scenario would lead to a global temperature rise of 2.5 C by 2060, slightly higher than the 2024 projection, as some clean energy commitments have been weakened by policy shifts, particularly in the United States.

The difference between the two scenarios when it comes to oil demand growth depends on the pace of electrification of the transportation sector, which accounts for around 45% of global oil consumption today. “Therefore, how the electrification of the transportation takes place, especially countries beyond China and Europe, will determine the shape of the oil demand growth,” Birol said in his presentation.

The IEA included its “Net Zero by 2050” scenario, first introduced in 2021, which sets out a pathway to achieving carbon neutrality by mid-century and suggested there would be no need to invest in new oil and gas production capacity if the target is to be attained. It was this scenario that drew the ire of OPEC and major oil producing countries, including Saudi Arabia and the United States, as well as some of the leading energy companies. Saudi Energy Minister Prince Abdulaziz bin Salman at the time famously called the “Net Zero by 2050” report a “La La Land” scenario. The prevailing argument by OPEC and others is that it is unrealistic to expect fossil fuels to be phased out before the end of the decade and be replaced by renewable energy. That narrative has gained traction given the massive demand for energy from data centers needed to power the anticipated surge in artificial intelligence, which renewables alone cannot meet.

Explosive Growth in Electricity Demand

The IEA outlook refers to “explosive growth” in electricity demand for data centers and AI. The IEA expects investment in data centers to reach $580 billion this year, exceeding the $540 billion being spent on the global oil supply. “A tripling of the amount of electricity consumed by data centres by 2035 represents less than 10% of total global electricity demand growth, but it is highly concentrated geographically. More than 85% of new data centre capacity additions over the next ten years are expected in the United States, China and the European Union – and many are located near existing data centre clusters, putting additional strain on congested grids,” the report noted.

All three scenarios show that “by 2035, sectors accounting for more than half the global economy will be dependent on electricity,” Laura Cozzi, one of the lead authors of the IEA report, said during the presentation. The industrial sector, electric vehicles, and air conditioners account for more of the growth in electricity demand than data centers.

Much of that electricity will be generated from renewables, which are set to become the single largest energy source by the early 2040s, providing 40% and 45% of incremental supply in the Current Policies and Stated Policies scenarios, respectively. Yet even this growth does not counteract the momentum behind fossil fuels – particularly as demand for oil products, such as gasoline and diesel, remains resilient, and countries prioritize energy affordability over emission cuts. The Stated Policies Scenario takes into account the change in U.S. energy policy direction under the One Big Beautiful Bill Act, which prioritizes oil, gas, coal, and nuclear power over renewable energy. This, the IEA noted, means that “the United States has 30% less renewables capacity installed in 2035 than in last year’s Outlook,” and 60% fewer electric vehicles on the roads. However, renewable energy deployment continues to expand globally.

In the Current Policies Scenario, the IEA sees the OPEC+ oil producers, particularly the Gulf countries, as the largest contributors to additional supply to 2050. Production from the group, which is led by Saudi Arabia and Russia, is projected to rise to a record 62 mb/d in the Current Policies Scenario. This is 15% higher than at any time in history, according to the IEA. Saudi Arabia alone could exceed 13 mb/d by mid-century if it reverses its recent decision to halt capacity expansion beyond 12.5 mb/d.

But the IEA also noted that while OPEC+ would represent a 55% share of the global oil market by 2050, that pales in comparison with China’s control over critical minerals. This is one of the many security threats that the IEA highlighted in the report.

“Energy is at the heart of today’s geopolitical tensions, with traditional risks to fuel supply now accompanied by restrictions affecting supplies of critical minerals,” the IEA warned. “The electricity sector – so essential to modern economies – is also increasingly vulnerable to cyber, operational and weather-related hazards.”

Chinese Dominance of Critical Minerals

Birol used the report’s launch to underline that the world is facing “an unprecedented range of security threats.” Some are familiar – the war in Ukraine, instability in the Middle East, attacks on Red Sea shipping. But increasingly, the threats are economic and technological, centered around the materials that make clean energy possible.

According to the IEA, China controls roughly 70% of the global processing capacity for key minerals, such as lithium, cobalt, rare earths, and nickel – all vital for renewable technologies, batteries, and even defense systems.

That concentration gives Beijing enormous leverage over the pace of the energy transition. Recent Chinese export restrictions on certain minerals, imposed as part of its trade tensions with the United States, showed just how quickly geopolitics can rattle global supply chains. Although the restrictions were later paused following talks between U.S. and Chinese leaders, the threat of disruption to supply chains underscores the world’s vulnerability.

“The critical minerals issue is the new front line of energy security,” Birol said. And unlike traditional oil shocks, these supply risks could slow the very technologies meant to reduce dependence on fossil fuels.

The IEA’s findings reinforce what many analysts have argued in recent years: that the energy transition is not replacing fossil fuels as quickly as expected but rather is adding new layers of renewable energy on top of an expanding base of oil and gas. This dynamic is what some call “energy addition” rather than transition. Rising living standards in developing countries and geopolitical anxieties have pushed policymakers to favor energy affordability and reliability over aggressive decarbonization.

The IEA is careful to stress that none of its scenarios are forecasts – they are pathways, shaped by political choices. Still, the message is clear: The direction of travel is uncertain, and the risks are multiplying.

An Overheating Planet

Even under the most optimistic assumptions, the world is not on track to limit warming to 1.5 C without what the IEA calls a period of “overshoot,” when temperatures briefly exceed that target before falling back. Doing so would require large-scale deployment of carbon removal technologies that are, for now, largely unproven.

In the meantime, the IEA warned, the global energy system will remain vulnerable to shocks – from wars and trade disputes to supply shortages and price spikes. The challenge isn’t just building more solar panels or wind turbines; it’s ensuring that the materials, investments, and political cooperation exist to make those technologies resilient and accessible.

As Birol put it: “Global energy security today faces an unprecedented range of threats.” The numbers may shift with each annual report, but that conclusion – unfortunately – seems to be getting stronger.

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Qatari Minister of State for Energy Affairs Saad bin Sherida Al Kaabi and U.S. Energy Secretary Chris Wright issued an open letter to leaders of the EU countries on October 22 warning that the directive would lead to “unintended consequences for LNG export competitiveness and the availability of reliable, affordable energy for EU consumers.” The directive, set to come into effect between 2027 and 2029, would allow EU regulators to penalize companies that fail to meet net-zero and labor-standard requirements, with fines once proposed at up to 5% of global revenue. Though the European Commission has softened some provisions, the letter argued that the changes fall “grossly short.” The letter stated: “We write in this spirit, united in our views, to express our deep concern over the continued lack of action to address the universally acknowledged, serious, and legitimate concerns raised by the global business community regarding the Corporate Sustainability Due Diligence Directive.”

The CEOs of ExxonMobil, ConocoPhillips, and TotalEnergies, whose companies have stakes in Qatar’s LNG projects, have also slammed the proposed directive as extraterritorial overreach. They believe it would make Europe uncompetitive and endanger its energy security at a time when the EU is in the process of phasing out Russian gas imports.

ExxonMobil CEO and Chairman Darren Woods called the directive “probably one of the most irresponsible pieces of legislation I’ve ever seen passed anywhere in the world,” and he said it would lead to “catastrophic consequences” for the industry. At a German Marshall Fund forum in June, Woods called for the directive to be scrapped: “I think significant changes, if not a complete throwing out of CS triple D is needed if Europe’s going to be successful going forward.”

The directive has implications for the United States and Qatar, which stepped in to supply Europe with LNG to replace Russian pipeline gas following Russia’s 2022 invasion of Ukraine. The United States was the largest supplier of LNG to Europe in 2024, accounting for roughly half of total imports, according to Eurostat, the EU Commission’s statistical arm.

Should the LNG be diverted to less restrictive markets, Europe would have to scramble to secure alternative supplies, which would come at a cost. This would also have ramifications for Europe’s gas supply security as it prepares to ban Russian LNG imports by January 2027, part of the 19th package of sanctions against Russia.

Kaabi has warned that if the directive’s penalties and methane rules are applied, Qatar would “seriously consider alternative markets.” In comments broadcast by Al Jazeera television during a meeting of the Gas Exporting Countries Forum in Doha, he went further. “I would rather keep it in the ground than be penalized … with a 5% penalty on the CS triple D and then another 20% on the methane … I think keep it in the ground is an option. So, but I don’t think we have a market issue, and you’ll see us sign contracts in other locations in the very near future.”

These are not empty threats. Together, the United States and Qatar represent about 70% of the 10 trillion cubic feet per year of new liquefaction capacity expected online globally by 2030, according to the International Energy Agency. Asia – home to faster demand growth and fewer carbon constraints – would readily absorb redirected Qatari volumes, though not all volumes of additional LNG to come from the phased expansion of Qatar’s North Field have been committed.

The EU’s directive and methane-emission regulations form part of a broader policy architecture that includes the Carbon Border Adjustment Mechanism. These frameworks aim to embed climate compliance across entire value chains, ensuring that imported commodities meet European decarbonization standards.

Even after revisions, the directive still carries significant uncertainty for exporters. The European Parliament’s decision in October 2024 to reopen negotiations has fueled anxiety among suppliers, especially given that gas remains vital to Europe’s power-sector flexibility. The IEA projects European gas demand to decline by 10% between 2024 and 2030, yet even under that scenario, natural gas will remain essential for balancing renewable energy. A sudden contraction in LNG supply could therefore destabilize both energy prices and political confidence in the transition.

The standoff also coincides with a downturn in project investment. According to the International Gas Union’s “2025 World LNG Report,” only 14.8 million tons per year of new liquefaction capacity reached final investment decision in 2024 – the lowest level since 2020 and far below the 58.8 million tons per year approved in 2023. The few sanctioned projects, including Ruwais LNG in the United Arab Emirates, Cedar FLNG in Canada, Genting FLNG in Indonesia, and Marsa LNG in Oman, all incorporate low-carbon design, using renewable-powered compressors and carbon capture and storage. Ruwais will be the first Middle Eastern LNG terminal fully powered by grid electricity, while Marsa plans to draw 100% of its energy from a dedicated solar farm. The sharp fall in global final investment decision activity, combined with Europe’s regulatory tightening, heightens fears of an investment shortfall that could constrain supply later in the decade.

Qatar, for its part, continues to expand carbon-capture capacity at Ras Laffan, targeting 11 million tons of carbon dioxide per year by 2035 from 2.1 million tons today. This forms part of its strategy to market “low-carbon LNG” while maintaining a cost advantage. Yet the lack of a globally recognized definition for low-carbon LNG complicates certification and pricing. Without mutual recognition mechanisms, Gulf exporters may face higher compliance costs and potential exclusion from European markets despite genuine emission-reduction efforts.

From a market perspective, Europe’s regulations may accelerate a broader eastward pivot in LNG trade. Asian economies are projected to account for 60% of global gross domestic product growth to 2030, compared with only 7% for the EU. These markets – less prescriptive on carbon but rapidly industrializing – offer LNG exporters flexibility and long-term growth. Nonetheless, European demand, though declining, remains large enough to shape global pricing and contract structures. For producers like Qatar, maintaining optionality between Europe and Asia will be central to commercial strategy.

Europe cannot afford to alienate its alternative LNG suppliers once it halts Russian gas imports. By 2027, the EU intends to eliminate Russian LNG and by 2028 all pipeline gas. Replacing Russian gas would be that much harder if Qatar and the United States decide to market their LNG in less restrictive markets. This would undermine the very gas diversification strategy that the EU has had in place since 2022.

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U.S. Treasury Department sanctions on Rosneft and Lukoil target key sources of Russian revenue. Unlike the ineffective oil price caps seeking to lower Russia’s per-barrel revenue, or targeted designations of “dark fleet” tankers and their owners, these sanctions aim directly at two companies that account for almost half of Russian crude oil exports. The Treasury has blocked financial assets held by Rosneft and Lukoil, and their majority-owned subsidiaries, and barred financial transactions with these entities by U.S. individuals, companies, and financial institutions. The Treasury warned that “foreign financial institutions that conduct or facilitate significant transactions” with such entities could be subject to sanctions.

These measures are already having an impact. Lukoil now plans to sell its international assets to trading giant Gunvor, possibly at a hefty discount. And companies have until November 21 to wind down transactions with Rosneft and Lukoil. For most international companies, the threat of secondary sanctions is too big to ignore.

Time will tell whether Washington chooses the path of strict enforcement. Fellow G7 states seem confident that a coordinated effort can dial up pressure on Russian oil exports. Perhaps the administration of President Donald J. Trump is finally determined to force Russian President Vladimir Putin to get serious about negotiations over peace in Ukraine, even if this entails a hit to global oil supply. If not, sanctions will simply redirect volumes in an ever more opaque oil market, with Russia finding work-arounds, such as new trading entities.

Source: Kpler

Sanctions enforcement centers on Asian buyers, and events in the past few months suggest the Trump administration is more likely to lean on India rather than China. Russian oil exports to India have skyrocketed since 2022, reaching more than 2 million barrels per day in some months. In August, the White House imposed a “secondary tariff” of 25% on Indian goods over the country’s ongoing purchases of Russian oil, added to the 25% reciprocal tariff Trump had imposed on the world’s most populous country. India refused to bow to these tariffs, but now the threat of secondary sanctions has added pressure.

Reliance Industries, operator of the world’s largest refinery, has stated it will comply with new sanctions. Reports suggest it may declare force majeure on its 10-year term contract with Rosneft for up to 500,000 b/d and seek alternative supplies. Indian Oil Corporation will not stop importing Russian oil but reinforced that it will not deal directly with sanctioned entities. And HPCL-Mittal Energy, a joint venture between Hindustan Petroleum Corporation Limited and the Mittal Group, will suspend further purchases of Russian crude. Buyers in Turkey and elsewhere in the Mediterranean will share this caution.

Russian oil exports to China could be less affected, although Chinese national oil companies are wary of sanctions exposure. Since the October 22 Treasury sanctions were announced, state refiners appear to be scaling back their purchases. Private Chinese refiners – often labeled “teapots” despite the large size and sophistication of some of their facilities – are better positioned to avoid Western financial institutions and attendant sanctions exposure. Chinese independent refiners have bought volumes in recent years from sanctioned exporters Iran, Venezuela, and Russia. Perhaps after a pause to monitor enforcement, it will be back to business as usual.

If risk-averse buyers seek alternatives to Rosneft and Lukoil volumes, what are the most likely options? As always, crude quality matters. Most Russian seaborne crude exports are either medium sour or light sour. In the past two years, India imported an average of 1.3 mb/d of Urals crude – Russia’s main sour export blend, normally exported via its Black Sea and Baltic Sea ports. Buyers in India, China, Turkey, and elsewhere may seek alternative crude grades from the Gulf, Iraq, West Africa, and Europe. Trump claimed China would import more U.S. energy supplies after the recent U.S.-China trade truce, and other officials have suggested Russia’s buyers should turn to U.S. volumes instead. But there is a mismatch in crude quality. The bulk of U.S. crude exports are light, sweet crude that does not substitute for Urals. Lighter, lower-sulfur Eastern Siberia-Pacific Ocean crude exported by pipeline from Russia to China is less likely to be affected by sanctions.

What does all this mean for Gulf oil exporters? After the array of sanctions, embargoes, and market interventions by the United States and European Union in recent years, a greater share of traded oil has moved into the shadows. Dodgy traders, tanker owners, and suspect shipping practices have greased the wheels of this maritime trade. Individual crude exporters benefit from discontinuities and friction, for example, when refiners suddenly need alternatives. But what matters most for oil market management is the net gain or loss from market volumes.

To date, Western sanctions targeting Russian oil have yet to remove barrels from the market. This is by design. Policymakers in Washington and European capitals have typically been wary of tough measures that could drive up the price of gasoline or diesel for the average consumer. The new sanctions targeting Russian oil giants – and especially the threat of secondary sanctions – could have real teeth. Especially if Washington policymakers believe the market is heading toward the massive oversupply many anticipate for the first quarter of 2026, they will feel more confident about squeezing Russia’s oil exports.

So far, OPEC+ is not overreacting. On November 2, the “Group of Eight” producers that have led voluntary cuts since 2023 agreed to raise their production ceiling by 137,000 b/d in December but paused planned additions for the first quarter of 2026. This suggests that after raising output for months – although at slower rates than headlines and announced production ceilings would suggest – the producers’ club is wary of an oversupplied market. A decision by Trump to bring the hammer down on Rosneft and Lukoil could be just what the doctor ordered for Gulf oil exporters looking to add volumes and recapture market share. But for now, they will wait and watch. As with many other issues in the global economy and geopolitics, much depends on the decisions of the U.S. president.

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Oman has moved rapidly to position itself as a regional and global hub for green hydrogen, driven by economic diversification and climate goals under Vision 2040. While strategic ambition and active international engagement underscore its potential role in the future of clean energy, the country must navigate technological, economic, and resource-related challenges to fully realize these objectives.

Oman’s hydrogen ambitions – targeting 1.5 million tons annually by 2030 with over $50 billion in committed projects – place it close to Saudi Arabia’s Neom, which aims for 600,000 tons annually powered by 4 gigawatts of renewables, and rival the United Arab Emirate’s low carbon hydrogen capacity exceeding 1.4 million tons per year. Qatar, meanwhile, emphasizes blue hydrogen linked to natural gas and carbon capture. Unlike many Gulf peers reliant on blue hydrogen pathways, Oman stands out as the region’s most fully renewable-powered hydrogen economy, integrating production clusters at Duqm to anchor domestic demand and exports. This combination of relative scale and green structural orientation could give Oman a unique competitive position in the Gulf hydrogen landscape.

The Global Hydrogen Context: Promise vs. Market Realities

Hydrogen is not new to industrial use. For decades, gray hydrogen, derived from natural gas, has been used in refining and fertilizer production. What is new is the shift to green hydrogen, produced through electrolysis using renewable-powered electricity, making it virtually carbon free. Advocates hail hydrogen as indispensable for decarbonizing steel, cement, aviation, chemicals, and long-haul shipping.

However, even as governments adopt ambitious hydrogen roadmaps, practical progress remains uneven. Hydrogen Central has reported on a wave of canceled or postponed projects across Europe, North America, and Australasia. High costs, uncertain demand, and technical barriers have forced companies including ArcelorMittal, Iberdrola, Shell, BP, and Equinor to scale down their ambitions, while U.S. and Australian developers – including Air Products and Fortescue – have also pulled back from largescale projects. The mismatch between green hydrogen’s potential and its economic viability remains stark. For example, Luxembourg-based ArcelorMittal has scrapped plans to transition two plants in Germany to hydrogen-based green steel production, citing prohibitive costs. Yet, in the Gulf, flagship ventures, such as Neom in Saudi Arabia, are proceeding, buoyed by state support and long-term strategic bets.

This global slowdown contextualizes Oman’s ambitions. Unlike advanced economies struggling to retrofit existing infrastructure, Oman can build an energy transition architecture from the ground up, harnessing its abundant renewable resources and unencumbered industrial space. Nevertheless, Oman’s plans face the same structural cost hurdles that have undermined projects elsewhere. Its distinct advantages – geography, renewables, political stability, and strategic partnerships – must therefore be weighed carefully against these constraints.

Oman’s Renewable Energy Expansion as a Foundation

Green hydrogen is only as clean as the electricity that produces it. Thus, Oman’s hydrogen strategy depends first and foremost on scaling renewable capacity, a project that has accelerated in recent years.

Oman has committed to sourcing 30% of its electricity from renewables by 2030 and 60% by 2040. As of May, renewables comprised 11.5% of Oman’s energy mix. Large-scale solar plants have been pivotal, most recently the 500 megawatt Manah I solar facility, built by Shanghai Electric with France’s EDF and Korea Western Power, came online operating under a 20-year power purchase agreement with Nama Power. Other projects, such as Ibri 2, Dhofar 1, and upcoming Ibri 3 and Dhofar 2, are rapidly boosting capacity.

China has emerged as a central partner. LONGi Green Energy Technology Company has joined forces with Power Construction Corporation of China to providing high-efficiency solar modules for the North Oman Solar Project, powering production for Petroleum Development Oman, the country’s largest producer of oil and gas. JinkoSolar, a major Chinese rival to LONGi, has secured the contract to supply Oman’s first hydrogen-linked solar project, a 487.5 MW facility supporting green ammonia production.

Meanwhile, pioneering smaller-scale initiatives, such as Oman Data Park’s partnership with Solar Wadi to establish the country’s first green energy data center, showcase the capacity-building logic of leveraging renewables for both industry and services.

This ecosystem of renewable projects provides the physical basis for hydrogen electrolysis, without which Oman’s export ambitions would remain aspirational.

Oman’s Green Hydrogen Roadmap: Scaling Supply and Infrastructure

Oman has set a national target to produce 1 million tons of green hydrogen annually by 2030 and 8 million tons by 2050. Achieving such scale requires coordinated planning, institutional innovation, and foreign partnerships. In line with Sultan Haitham bin Tariq al-Said’s directive to fast-track hydrogen development, Oman established Hydrom, charged with overseeing concessions and coordinating upstream renewables with downstream hydrogen and ammonia projects. Hydrom’s portfolio now includes nine awarded projects in Al Wusta and Dhofar, together valued at more than $50 billion and designed to produce roughly 1.5 million tons of green hydrogen per year by 2030.

Oman is also prioritizing industrial clustering. Preliminary planning is underway for the development of a dedicated green hydrogen zone in the Duqm Special Economic Zone. Covering about 7 square miles, the zone aims to co-locate production plants, storage, export facilities, and service corridors, hosting downstream elements of at least five confirmed megaprojects. Duqm is emerging as a green industrial hub, with companies including France’s Engie and South Korea’s Posco contributing to the buildout.

Oman’s first green hydrogen and ammonia plant is already under construction, led by India’s ACME Group. Chinese partners, including Sungrow Hydrogen and Shuangliang Group, are supplying key electrolyzers and hydrogen production systems. Complementing these is an ambitious manufacturing partnership between Oman’s United Engineering Services and China’s Sungrow to build a local factory for electrolyzers and liquefaction systems.

These supply chain and infrastructure commitments address one of the major bottlenecks in global hydrogen rollouts, namely technology dependence. By localizing equipment production and inviting heavy industrial investors, Oman is seeking to move beyond pilot-scale hydrogen projects into creating genuine commercial anchors.

Industrial Anchors: Hydrogen and the Green Steel Value Chain

A key obstacle facing hydrogen economies worldwide is sustaining demand at scale. Oman’s ambition is not only to export hydrogen directly but to integrate it into industrial value chains that can anchor demand domestically while serving international markets.

One initiative is the Meranti Green Steel project, which aims to establish a 2.5 million ton per year green hot briquetted iron plant in Duqm. The project envisions an initial reliance on a gas and hydrogen mix before ramping up to mostly hydrogen by the end of the decade. The plant’s output is intended for Meranti’s green steel plants in Thailand and for European customers pursuing lower-carbon supply chains.

The importance for Oman lies both in demonstrating hydrogen’s role as a commercially viable fuel for heavy industry and in creating the conditions for Omani steel to be integrated into international markets undergoing a shift toward greener materials. Green hydrogen-enabled industries therefore serve as a bridge between Oman’s domestic energy infrastructure and global decarbonization markets, ensuring that these projects are not stranded assets but are aligned with long-term industrial and commercial demand.

Financing the Transition: Sovereign Investment and International Partnerships

Hydrogen megaprojects require unprecedented financing commitments. To support the country’s energy transition and emerging hydrogen sector, the $200 million Future Fund Oman was established as a joint initiative between the sovereign investment authority and Hong Kong’s Templewater. The fund is designed to catalyze investment in renewable energy, electrofuels, green data centers, and low-carbon mobility, strengthening both domestic capacity and Oman’s position in global low-carbon markets.

Beyond domestic capital, Oman actively seeks international partnerships. At the Oman-Korea Green Hydrogen Investment Forum in August, the Ministry of Energy invited Korean companies to join Omani projects, emphasizing shared ambition and Korean technological capacities. Japan, South Korea, China, and India – each possessing ambitious hydrogen import agendas – represent important target markets, while Oman also courts European partnerships. Its balanced diplomacy allows it to navigate great power rivalries, securing investment from China, India, Korea, and Europe simultaneously.

Strategic Geographies: Europe vs. Asia

Oman’s location on the Arabian Sea provides a strategic advantage for hydrogen exports, offering shorter transit times and potentially lower shipping costs to major Asian markets, including India, Japan, South Korea, and China. At the same time, Europe remains a politically and commercially significant target given the European Union’s increasing reliance on hydrogen for decarbonizing steel, chemicals, and heavy transportation.

Duqm, in southeastern Oman, is positioned as the cornerstone of a dual-market export strategy. It anchors an envisioned Oman-Europe liquefied hydrogen corridor while serving as the operational hub for shipments to Asia. The site’s development has been accelerated by Chinese participation. Firms such as Sungrow Hydrogen and Shuangliang Hydrogen have supplied critical equipment and contributed to port infrastructure, industrial zones, and ancillary facilities that integrate renewable generation, electrolysis, and downstream logistics. These partnerships enhance the scalability and technological readiness of Duqm, aimed at transforming it into a comprehensive hydrogen hub rather than a simple export terminal.

Europe offers credibility and a politically backed market, but cost competitiveness remains a challenge; delivered liquefied hydrogen could exceed current European production costs. Asia, in contrast, provides both proximity and scale, with the combined demand of Japan, South Korea, China, and India forming a large and expanding market for green hydrogen and ammonia. By leveraging Duqm as the operational center for both corridors, Oman can validate its hydrogen production in the European market while capturing volume and diversification opportunities in Asia.

This dual-market approach also aligns with Oman’s broader diplomatic strategy of neutrality and multidirectional engagement, reducing dependency on a single region while maximizing strategic flexibility. By integrating domestic renewable energy assets with industrial-scale hydrogen production and export logistics at Duqm, Oman is creating a sustainable, commercially viable pathway for the country’s hydrogen ambitions. Chinese firms’ involvement has been pivotal in enabling this integrated model, providing technology, infrastructure, and expertise that strengthen Oman’s competitive position in both European and Asian hydrogen markets.

Structural Constraints: Technology, Water, and Economics

Oman’s hydrogen strategy is ambitious but faces critical headwinds. First is technology dependence. Oman does not yet manufacture electrolyzers at scale, relying heavily on Chinese partnerships. While joint ventures including United Energy Services-Sungrow aim to fill this gap, dependency raises strategic risks.

Second is water availability (and costs associated with it). Electrolyzers require vast volumes of water – fresh, seawater, or treated wastewater. In an arid country like Oman with scarce water resources, this creates potential trade-offs. Advanced seawater desalination and water recycling will be required, adding to expenses.

Third, and most fundamental, is price competitiveness. Omani planners aim for production at $2 per kilogram by 2030, yet current benchmarks suggest prices at nearly double that. Without international subsidies, regulatory frameworks, or carbon pricing mechanisms that privilege low-carbon fuels, Oman may struggle to sell hydrogen profitably in distant markets.

The Diplomatic and Industrial Dimension: Asia, China, and Balanced Geopolitics

China has emerged as a central player in Oman’s hydrogen sector. Chinese firms have won substantial contracts to supply hydrogen production equipment, especially for large green ammonia and hydrogen projects in Oman. China is embedding itself across Oman’s hydrogen value chain by supplying panels (JinkoSolar), electrolyzers (Sungrow, Shuangliang), and full hydrogen systems (Xinsichuang Hydrogen) and engaging in research and development partnerships, including collaboration on liquefaction technologies with Sultan Qaboos University. Joint interests extend to hydrogen fuel-cell trucking and supply chains.

This partnership is also geopolitical. As U.S.-China tensions constrict Beijing’s access to Western cleantech markets, the Middle East provides fertile terrain for Chinese industries, and Oman is a crucial partner.

Oman’s neutral diplomatic posture – cultivating ties with Europe, Asia, and competing Gulf neighbors – thus becomes an asset, insulating it from overreliance on one bloc. This balance is central to maintaining export flexibility and long-term sovereignty in a competitive global hydrogen market.

Challenges Ahead

Oman’s dual-market hydrogen strategy – anchored at the Duqm hub and supported by strategic partnerships, including major Chinese technology and infrastructure players – positions the country to meet both European and Asian demand while advancing domestic economic diversification.

Yet challenges remain. Cost competitiveness, water scarcity, and global market volatility require careful navigation. Looking ahead, initiatives like the 2025 Green Hydrogen Summit Oman – which will bring together over 3,000 participants to focus on regulatory, financing, and infrastructure priorities – demonstrate Oman’s active role in implementing its hydrogen strategy.

By linking domestic renewable energy capacity with industrial-scale production and export corridors, Oman is building a tangible, forward-looking framework to transform its hydrogen ambitions into a sustainable and globally relevant industry, reinforcing its Vision 2040 and net-zero objectives.

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The IEA noted that this is the equivalent of adding the current demand of Germany and Spain combined, a challenging task for a region already grappling with extreme heat and water scarcity due to “accelerating climate pressures.” In the report, “The Future of Electricity in the Middle East and North Africa,” the IEA estimated that, between now and 2035, cooling and desalination together will account for 40% of projected growth in electricity demand in the region. Other key drivers are industrial growth, the electrification of the transportation sector, urbanization, and the new digital economy.

“Demand for electricity is surging across the Middle East and North Africa, driven by the rapidly rising need for air conditioning and water desalination in a heat- and water-stressed region with growing populations and economies,” IEA Executive Director Fatih Birol said in a statement about the findings of the report. “To meet this demand, power capacity over the next 10 years is set to expand by over 300 gigawatts, the equivalent of three times Saudi Arabia’s current total generation capacity,” he added.

One-quarter of households in the Middle East and North Africa currently have air conditioning, compared with near-universal saturation in the Gulf states. As incomes rise and temperatures climb, cooling alone could add 175 terawatt-hours of new demand, nearly one-quarter of the projected growth.

Water scarcity compounds the challenge. The Gulf accounts for 70% of today’s desalination capacity, but demand for fresh water is rising across the region. The IEA expects electricity use for desalination to triple by 2035, adding more than 100 terawatt-hours.

Electricity demand in the region has been on the rise even as the major economies have become more service oriented. The IEA estimates that electricity demand tripled between 2000 and 2024, increasing to 1,000 terawatt-hours, making it the third-largest contributor to global electricity demand growth after China and India.

Much of this high level of demand growth is due to subsidies and the absence of effective energy efficiency measures in all but a handful of countries. The IEA estimates that over the past decade, the region has spent an average $250 billion per year on fossil fuel subsidies with electricity subsidies alone accounting for more than $80 billion. These fuel subsidies are a drain on the economy and make power generation uneconomic in some countries because power suppliers cannot cover their operating costs. Subsidy reforms have been introduced by some countries, including Saudi Arabia, the United Arab Emirates, and Egypt, although rates generally remain below reference prices. Subsidies are a particular burden on countries that are net importers, including Egypt and Kuwait. Furthermore, the region’s economies remain energy intensive, despite a decline in the contribution of the industrial sector to gross domestic product. This has contributed to a rise in carbon dioxide emissions – the CO2 intensity of GDP rose by 11% between 1990 and 2023, compared to a global average decline of 37% over the same period, the report noted.

Historically, countries in the region relied on oil and natural gas for power generation, but that mix of fuels is shifting as more renewables capacity comes online. In 2023, fossil fuels accounted for 90% of generation, with oil alone making up one-fifth. By 2035, oil’s share will fall to just 5% as it is displaced by gas and renewable energy. Installed renewable capacity, just 6% of the total in 2024, could rise to nearly 300 gigawatts by 2035 to make up one-quarter of all generation. Solar and wind will dominate, accounting for 60% of all new capacity additions.

The shift is not simply about climate commitments. For Saudi Arabia, Iraq, and Kuwait, reducing the amount of oil that is burned to generate electricity frees up crude for exportation. If oil displacement falters, the IEA estimates regional economies could forfeit $80 billion in export revenue and face $20 billion in import bills.

The scale of change is huge, and progress will be uneven. Gulf Cooperation Council states, with substantial resources and favorable investment environments, are advancing modern grids and large-scale renewables. In contrast, countries with outdated infrastructure and weaker economies may face challenges in upgrading grids or drawing major investments. “A resilient grid is the backbone of a reliable clean power system,” the IEA noted. Yet many countries still face high transmission losses and inadequate infrastructure.

The IEA projects power sector investment to grow by 50%, from $40 billion in 2023 to $60 billion in 2035, with half dedicated to transmission and distribution.

Battery energy storage is also expected to play a growing role, with capacity rising from barely 1 GW to 7 GW by 2035. Egypt, the UAE, and Saudi Arabia are leading early adoption, with the kingdom targeting 48 gigawatt-hours of storage by 2030.

Two emerging sectors could reshape the regional electricity story: green hydrogen and data centers. If announced hydrogen targets materialize, the sector could become the largest source of new demand as electrolyzers needed for production of green hydrogen require a vast amount of renewable energy. Yet progress has been slow. Saudi Arabia’s flagship Neom project, due online in 2027, remains the most advanced, but cost barriers and difficulties in securing firm buyers have slowed momentum across the region. Meanwhile, data centers are multiplying as the Middle East is carving out a role as a digital hub. Gigawatt-scale projects are being planned in Saudi Arabia and the UAE, though the full impact on electricity demand remains unknown.

Saudi Arabia has set an ambitious target to displace oil in power generation. Total power generation capacity is set to double from 100 GW to 200 GW by 2035. The kingdom plans to eliminate oil from its generation mix by 2030, replacing it with a 50:50 balance of gas and renewables.

Saudi Arabia is targeting 130 GW of renewables by 2030. Even the IEA’s more cautious projection of “nearly 100 GW” would give the kingdom one-third of the region’s total renewable buildout. The stakes are enormous. Failure to displace liquids could cost Riyadh $150 billion in lost oil export revenue over the next decade. But, if successful, Saudi Arabia would set the template for the wider region – proving that even an economy long defined by oil dependence can pivot to a cleaner, more diversified power system.

Nuclear energy is another potential source of power supply for the Middle East and North Africa. There are five nuclear reactors operational in the region, including four in the UAE, that have been commissioned in the past five years, adding to the existing nuclear power station in Iran. A new nuclear power station is under construction in Egypt and one in Iran, while the UAE is considering an expansion of its nuclear capacity. Saudi Arabia is also advancing plans for its first nuclear unit. These proposed projects would triple nuclear capacity to 19 GW by 2035.

The next 10 years will determine whether the Middle East and North Africa can balance soaring electricity demand with sustainable supply. Cooling, desalination, and urban growth will keep pressure on systems already stretched thin. Oil’s retreat from the power mix creates both risk and opportunity. And while the Gulf states are well positioned to lead, others risk falling behind.

Electricity demand in the Middle East is rising at a pace the world has never seen before. How the region responds will shape not only its economic future but also the global energy landscape.

The post The MENA Power Transformation: Meeting Unprecedented Demand appeared first on AGSI.

Far more than a bilateral deal, the agreement signals a deepening of Russia’s strategic realignment toward China, recalibration of Beijing’s energy security posture, and – most consequential for the Gulf – direct challenge to the long-term assumptions underpinning the global liquefied natural gas industry. Cheap Russian pipeline flows could weaken Asian LNG demand, depress global prices, and force Gulf exporters to rethink the foundations of their growth strategies.

Russia’s Pivot, China’s Leverage

For Russia, the Power of Siberia 2 pipeline represents the culmination of a pivot eastward that began in earnest after the invasion of Ukraine in 2022, when sanctions and political rupture with Europe shattered the foundations of Gazprom’s traditional export model. Europe, once the largest market for Russian gas, has since moved rapidly to replace pipeline flows with LNG sourced from the United States, Qatar, and other suppliers. Faced with the collapse of its Western market, Moscow has looked to Beijing as the anchor for its future energy strategy.

For China, however, the pipeline offers more than just diversification of supply. It underscores a shift in Beijing’s approach to Moscow. In the immediate aftermath of the Ukraine invasion, Chinese firms froze joint investment while maintaining commodity purchases. Now, the pipeline agreement suggests Beijing is prepared to go further. It indicates a readiness to secure cheap long-term gas, exercise leverage over Russia, and assert a role as a decisive force in shaping the global gas market.

Pipeline Bargaining Power: Beijing in Control

The asymmetry in the Russia-China relationship is striking. In every major dimension of negotiation – from price to contract flexibility, from financing to timing – Beijing holds the upper hand. China is unlikely to pay European- or Asian-linked benchmarks; instead, it will demand terms similar to those of Power of Siberia 1, where Russian gas already arrives at some of the cheapest rates in China’s portfolio.

Even financing may tilt toward Beijing’s advantage. While Russian pipelines have traditionally been funded by Gazprom alone, the sheer scale of Power of Siberia 2 – estimated at $14 billion – could lead to Chinese loans or equity participation. Such a move would ease Gazprom’s financial burden while reopening the broader question of Chinese investment in Russia’s energy sector. Finally, the timeline itself serves Chinese interests. Because the pipeline has not entered full-scale development, China can delay terms or flows indefinitely, effectively holding an option on discounted gas while Russia has already committed politically.

LNG Competition and the Gulf Exporters

Even the prospect of Power of Siberia 2 could disrupt global LNG markets. If China substitutes significant LNG demand with cheaper Russian pipeline gas, investment plans worldwide – from the United States to East Africa – could face fresh uncertainty. For Gulf exporters, the risk is particularly acute. Given that they are heavily concentrated in Asia, Qatar, Oman, and the United Arab Emirates could confront softer markets, intensified competition, and greater buyer leverage.

Such a scenario would place downward pressure on long-cherished contractual practices. For decades, Gulf producers preferred oil-linked long-term contracts, which provided stable revenue and protected against volatility. Yet China’s ability to secure ultracheap pipeline gas will strengthen its insistence on more flexible terms, potentially forcing Gulf exporters to adjust their models. Lower margins would become the norm, even for producers with strong cost advantages.

In response, Gulf producers may have to accelerate diversification of their customer base. Europe stands out as an obvious alternative. Having weaned itself off Russian pipeline gas, Europe will need long-term LNG supply to ensure energy security, even as it pursues decarbonization. Qatar, already a significant supplier to Europe, has signed several long-term deals in recent years. Oman and the UAE, though smaller players, also see opportunities to increase their presence. South and Southeast Asia present another avenue, with countries such as India, Pakistan, Bangladesh, and Vietnam expected to continue growing their gas demand even if China moderates its intake.

Yet even with such diversification, the strategic rivalry with Russia looms large. Moscow’s tightening energy partnership with Beijing is not only commercial but geopolitical, reinforcing a triangular competition with the United States and challenging Gulf producers’ influence in Asia. Russia’s willingness to sell at a discount may force others to either accept lower prices or redirect their cargoes. For Oman and the UAE, with smaller scale and higher vulnerability to market swings, this represents a particular challenge.

Qatar and Its Neighbors: Divergent Fortunes

No Gulf producer is as directly affected by the Russia-China alignment as Qatar. With vast LNG reserves and ambitious expansion plans, Doha hopes to position itself as the world’s preeminent supplier. Qatar’s North Field expansion could lift production from 77 million to 142 million tons by 2030, reflecting a strategy built on rising global LNG demand. The Power of Siberia 2 complicates this outlook, as reduced Chinese appetite for seaborne cargoes could pressure revenue, price negotiations, and contract flexibility. While Qatar’s ultralow costs ensure competitiveness even in weak markets, competitiveness alone does not guarantee profitability at the massive scale envisioned.

Moreover, the timing of Qatar’s new capacity additions coincides with the potential onset of oversupply. Its strategy depends on markets tightening toward the end of the decade, a window when demand is projected to absorb the new volumes. If instead the market remains loose due to Russian pipeline flows into China, Qatar may find itself selling additional cargoes into a buyers’ market at depressed prices. To adapt, Doha is likely to double down on deepening ties with Europe. The continent’s quest for energy security in the wake of Russia’s invasion of Ukraine has opened doors for long-term partnerships, and Qatar has already moved aggressively to fill that void with new contracts in Germany, France, and Italy. At the same time, Doha will likely look beyond Europe to South and Southeast Asia as the next frontier of demand growth. Countries such as India, Vietnam, Bangladesh, and Pakistan are building out gas infrastructure and remain structurally dependent on imports. For Qatar, securing a strong foothold in these markets will be essential to offset any erosion of Chinese demand.

Qatar’s adaptation extends beyond geography to the very nature of LNG contracts. Once reliant on rigid 20-year oil-linked agreements, it is now embracing hybrid structures that blend oil-linked and spot-based elements, allow volume flexibility, and leverage downstream investments to secure long-term market share. This nimbleness, combined with ultralow costs and a strong global reputation, gives Qatar resilience in the Power of Siberia 2 era.

By contrast, Oman and the UAE, while expanding LNG capacity, lack Doha’s economies of scale, cost advantages, and market position. Their greater exposure to market swings means that persistent oversupply and Russian pipeline competition could force project delays or reductions, threatening their ability to attract buyers and command favorable terms.

Still, Qatar and its neighbors are not without options. Qatar has already diversified with long-term contracts in Europe and South Asia, while Oman and the UAE are also exploring new markets. For all three, contractual innovation will be key – moving away from rigid oil-linked terms toward hybrid pricing, flexible volumes, and downstream investments, such as regasification terminals and trading ventures. Perhaps most important, Qatar’s reputation as a reliable and flexible supplier affords it credibility in markets that value stability.

Scenarios for Gulf LNG in a Russia-China Era

The trajectory of the Power of Siberia 2 pipeline casts a long shadow over the Gulf’s LNG ambitions. And three scenarios stand out for the future of Gulf LNG in a Russia-China era.

In the first, Power of Siberia 2 moves forward but more slowly than planned. Under this scenario, China takes in some Russian pipeline gas but continues to import large volumes of LNG to meet incremental demand. Competition intensifies, margins tighten, but Qatar remains well placed to endure thanks to its low-cost base and global reach. Oman and the UAE can still find markets, but their footing is less secure, and they are more vulnerable to buyer pressure on pricing and flexibility.

In the second, more pessimistic case, Power of Siberia 2 reaches full capacity, and China leans heavily on Russian supplies. This outcome drastically reduces LNG demand growth, pushing the global market into oversupply and depressing prices. Margins across the board are squeezed, and higher-cost projects are delayed or canceled. Qatar remains viable but significantly less profitable, while Oman and the UAE face serious LNG difficulties. Their smaller scale and thinner margins make it hard to sustain expansion plans, and their governments may be forced to step in with subsidies or consider shelving projects altogether.

Finally, in the most optimistic case, geopolitical or logistical obstacles hinder Power of Siberia 2 leaving China still dependent on LNG growth. In this scenario, Qatar’s massive expansion coincides with strong demand, reinforcing its role among the world’s preeminent LNG suppliers. Oman and the UAE also benefit, but in relative terms their gains are modest compared to Qatar’s dominance.

Adaptation Amid an Altered Global Energy Chessboard

The reality, of course, will likely fall somewhere in between these scenarios. What is already clear is that the Power of Siberia 2 agreement has altered the global energy chessboard. By aligning more closely with Russia, China has injected uncertainty into LNG market projections and forced every major producer – from Texas to Doha – to recalculate.

For Gulf exporters, the challenge is to adapt to a new era of intensified competition and shifting demand or risk being sidelined. For Qatar, the stakes are particularly high. Its ability to diversify markets, embrace contractual innovation, and leverage its structural advantages will determine whether its massive LNG expansion secures the dominance it envisions or leaves it struggling in a crowded marketplace. For Oman and the UAE, the next decade could decide whether they remain meaningful players in the LNG trade or are relegated to the margins by an unforgiving price environment. Should the pipeline come online, the Russia-China axis would reshape the map of gas competition, making adaptation the key determinant of which Gulf producers endure.

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With gas production on the rise, the kingdom is on track to satisfy growing demand for gas for electricity generation and end the practice of burning oil to generate power, a costly and environmentally harmful method that has required the kingdom to burn an average 1 million barrels per day of oil in recent years, according to figures from the Joint Organizations Data Initiative. By replacing oil with gas and renewable energy, Saudi Arabia will free up an equal volume of oil that it could export to the global market without the need to invest in new production capacity.

Because revenue from oil sales makes up 70% of total export earnings, Saudi Arabia is sensitive to oil price volatility. Oil export revenue sank to a four-year low of $15.8 billion in May as oil markets were roiled by the April announcement of sweeping U.S. trade tariffs. But by June, revenue had risen to a three-month high of $17.2 billion, as oil prices rose briefly during the June conflict between Iran and Israel. While prices have since fallen back, they remain above May levels, when the price of Brent crude averaged $64/bbl.

Despite low oil prices pushing Saudi Arabia’s budget into deficit, preliminary government figures show that economic activity was strong. The economy grew by 3.9% in the second quarter compared with the second quarter of 2024, according to preliminary estimates by the General Authority for Statistics. The industrial production index was up 7.9% year-on-year in June at 111.9, the highest since January 2023.

The improved price environment since the May dip coincided with the accelerated unwinding of voluntary cuts by the OPEC+ alliance that began in April. Saudi Arabia’s allocation will rise to 9.978 million barrels per day for September and 10.02 mb/d for October after the group on September 8 agreed to a second round of tapering voluntary cuts. If coupled with higher prices, this would mean higher oil export earnings in the final quarter of the year.

The impact of price gyrations was reflected in Saudi Aramco’s second quarter results, which showed that net income fell by 22% year-on-year to $22.67 billion, as the average realized price of Saudi crude oil fell below $70/bbl for the first time since 2021. However, the Saudi oil giant is sticking to its dividend and investment strategy, with a huge investment program focused on gas. Aramco aims to maintain crude oil production capacity at 12 mb/d but is targeting a 60% increase in gas production capacity by 2030.

The largest increment will come from the Jafurah unconventional gas field development, where Saudi Aramco secured a “lease and leaseback” financing arrangement for $11 billion with an international consortium led by BlackRock’s Global Infrastructure Partners. Aramco released a statement noting that as part of the transaction “a newly-formed subsidiary, Jafurah Midstream Gas Company (JMGC), will lease development and usage rights for the Jafurah Field Gas Plant and the Riyas NGL Fractionation Facility, and lease them back to Aramco for a period of 20 years.” Aramco will pay the company for the exclusive right to receive, process, and treat raw gas from Jafurah. Aramco will hold a 51% majority stake in JMGC, with the remaining 49% held by investors of the BlackRock-led consortium.

Jafurah is estimated to hold 229 trillion standard cubic feet of raw gas and 75 billion barrels of condensates and is a “key component in Aramco’s plans to increase gas production capacity by 60% between 2021 and 2030, to meet rising demand,” the statement highlighted. First gas production from the Jafurah Basin is due to come online in the fourth quarter of this year, yielding 200 million cubic feet per day.

Total gas output, which includes sales gas and ethane, was already up by more than 6% year-on-year during the first half of 2025 with other increments due by year-end. Associated gas output will rise through the third quarter as OPEC+ crude production cuts are eased and two major gas projects begin operations before the end of the year. This would put Saudi gas production on track for the largest annual increase in at least a decade.

Despite these increases, Saudi Arabia still suffers from a domestic gas shortfall to supply power plants, forcing it to burn oil – both crude oil and liquid fuels – to generate electricity. The amount of oil used in power generation has averaged more than 1 mb/d in recent years but has been in decline since 2022, as it is being displaced by natural gas. Joint Organizations Data Initiative statistics show that direct oil burn averaged 943,000 b/d during the first half of the year, even as electricity demand soared by 10% year-on-year, driven by industrial activity.

The improved outlook for gas is due mainly to stepped up investment in nonassociated gas fields as well as a contribution from associated gas since OPEC+ began to unwind voluntary cuts in April. Gas accounts for around 50% of power generation in Saudi Arabia, and the availability of more gas will help to replace oil liquids in power stations serving the capital Riyadh as well as the industrial hubs of Yanbu and Rabigh. So far, most of the recent growth has come from nonassociated gas projects that came online in 2023, adding 1.3 billion cubic feet per day from two expansion projects and the first phase of the Ghawar unconventional gas development.

Later this year, Aramco is due to bring online the 2.6 billion cubic feet per day Tanajib gas processing plant, which will handle associated and nonassociated gas from the Marjan and Zuluf offshore field expansion projects, yielding 650 million cubic feet per day of sales gas. The Marjan, Zuluf, and Berri oil field expansion projects will produce 1.15 mb/d of crude oil, which will replace natural decline at older fields and maintain the kingdom’s total oil production capacity at 12 mb/d. The next big project is the 1.3 billion cubic feet per day expansion of the 2.5 billion cubic feet per day Fadhili gas processing plant, which will take capacity to 3.8 billion cubic feet per day when completed by 2027.

Overall, Aramco plans to increase gas production capacity to around 15 billion cubic feet per day by 2030 as part of the Liquids Displacement Program to eliminate oil burn by 2030, by which time it hopes to have a 50:50 mix of renewables and gas in the power sector.

In response to sharply higher demand for electricity, Saudi Arabia has stepped up its renewables drive with a series of awards to developers – in July alone 15 gigawatts of power purchase agreements were concluded. As a result, total renewables capacity is expected to nearly double to 12.7GW by the end of 2025 and 20GW in 2026.

As renewables are expected to make up a significantly larger share in the power mix, the Saudi Electricity Company is investing in battery storage facilities to manage intermittency. In its 2024 annual report, the company listed its plans to add 48 gigawatt hours of battery energy storage system by 2030, which it described as “the largest deployment in the GCC region, to ensure grid stability and maximize renewable energy utilization.”

With Saudi Aramco maintaining its investment strategy, regardless of oil price movements, and the government setting clear policy guidelines and targets, Saudi Arabia is well on the way to achieving its targets. It will be able to eliminate oil burn and transform its power grid to run on gas and clean energy with sufficient backup to maintain grid stability.

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