The collaboration between Chevron and Helleniq Energy is not new. The two entities are already partners in multiple offshore exploration blocks recently awarded by Greece. With this latest application for a Greek offshore exploration block, Chevron intends to further solidify its operational presence and assume the role of operator for an additional exploration area.

Stavros Papastavrou, Greece’s Minister of Energy and Environment, said, “Chevron’s decision to participate in yet another offshore area of our country together with Helleniq Energy is a significant milestone in the national effort to develop the oil and gas sector.”

“Greece is constantly strengthening its position on the energy map of the Eastern Mediterranean,” he added.

Earlier this year, a consortium led by Chevron, which includes Helleniq Energy, finalized lease contracts for oil and gas exploration activities offshore Greece. This initiative aligns with Greece’s strategic objective to emerge as a prominent gas supplier in the Mediterranean region. In February, the Chevron-Helleniq Energy partnership formalized lease agreements with Greece concerning the exploration of four distinct offshore blocks. These areas are located south of Crete and the Peloponnese.

Collectively, these four offshore blocks – identified as South Crete 1, South Crete 2, South of Peloponnese, and Block A2 – span an expansive territory of approximately 47,000 square kilometers, which equates to roughly 18,147 square miles. Under the established terms of these lease agreements, the joint venture between Chevron and Helleniq Energy is set to implement a comprehensive three-phase exploration program. The primary goal of this program is to thoroughly assess the hydrocarbon potential inherent in these designated areas. These developments with the recent request for a 70% stake in a Greek offshore exploration block highlights Chevron’s intention to expand its overseas operations.

The expanded deployment of well and integrated field planning is designed to foster faster and more consistent decision-making. This is crucial as operators work to sustain production from mature offshore assets while simultaneously navigating increasing development complexities. The partnership aims to achieve similar benefits for integrated field development planning.

As part of this enhanced collaboration, Vår Energi is implementing the Delfi™ digital platform. This platform is set to connect various stages of operations, including exploration, subsurface evaluation, well planning, subsea design, field development planning, and production, all within a cloud-native environment. By enabling teams to work concurrently on shared data and standardized workflows, the approach is expected to minimize handoffs and rework.

Rakesh Jaggi, president of SLB’s digital business, highlighted the importance of digital environments in today’s complex offshore developments. He said, “As offshore developments become more complex, performance increasingly depends on how quickly teams can align, evaluate options and make decisions using trusted data.”

“By bringing disciplines together in an integrated digital environment, operators can shorten planning cycles and improve the speed and quality of decisions needed to progress opportunities, including marginal subsea tiebacks,” he added.

The expanded collaboration between SLB and Vår Energi for well and integrated field planning underscores a broader industry trend towards cloud-based planning. These approaches are vital for operators seeking to reduce the time between key development milestones, enhance coordination across different disciplines, and maximize the value derived from existing resources in mature basins. This focus on digital collaboration is key to efficient digital field planning.

The proposed framework represents a significant policy development for the country as it seeks to establish strategic oil reserves and enhance long-term supply resilience. Through POWERR Asia, the DOE aims to create additional supply buffers while reducing the nation’s dependence on unhedged, spot-market imported fossil fuels. As part of the initial phase, the government intends to build entirely new, state-of-the-art stockpiling facilities. Supporting this process, the Ministry of Economy, Trade and Industry of Japan is expected to send technical experts in the coming days to issue the preliminary terms for comprehensive feasibility studies, formally launching the project’s development phase.

Following the start of the project, developers selected to participate will be required to adhere to a strict, multi-year construction schedule in order to achieve operational readiness. Those involved in the development process will also receive technical capacity building from the Economic Research Institute for ASEAN and East Asia and the Japan Organization for Metals and Energy Security. The DOE believes that the development of strategic oil reserves through these facilities will strengthen the country’s preparedness against future supply disruptions while creating a more resilient energy framework.

To reduce financial and construction-related risks, the DOE is encouraging project proponents to pursue joint ventures with Japanese trading companies and the Japan Bank for International Cooperation. This approach is intended to support execution across engineering, procurement, and construction activities while ensuring reliable project financing. The Philippines and Japan have already completed the foundational alignment of POWERR Asia, establishing a cooperation matrix that includes both government-backed technical assistance and direct private-sector capital participation to support the development of strategic oil reserves.

The infrastructure initiative follows earlier actions taken by the Marcos administration during the recent energy crisis. At the height of that period, the government utilized a ₱20 billion emergency fund to purchase approximately two million barrels of refined petroleum products and liquefied petroleum gas to stabilize domestic inventories. Since then, the DOE has suspended additional emergency procurement activities, stating that the country’s fuel reserves are currently at a comfortable level.

According to the African Energy Chamber (AEC), this evolving investment landscape is underpinned by growing balance sheet strength observed among African sovereign wealth funds, state-backed investment vehicles, and independent energy operators. This financial robustness is fostering a broader embrace of outward-focused investment strategies across the continent’s energy sector. The AEC projects that Africa’s upstream sector will achieve approximately 11.4 million barrels of oil equivalent per day (MMboed) in production by 2026, complemented by roughly $41 billion in upstream capital expenditure. This level of activity is cultivating a larger pool of experienced investors and operators actively seeking international growth avenues.

Brazil’s deepwater pre-salt developments are recognized globally as among the most competitive offshore oil projects. Concurrently, Argentina’s Vaca Muerta shale play is progressing into a new phase characterized by a strong emphasis on LNG exports, gas monetization initiatives, and crucial infrastructure expansion. The AEC highlights specific opportunities within Brazil, including its offshore gas infrastructure, floating production, storage, and offloading (FPSO) developments, and the subsea supply chain. In Argentina, the focus is on planned pipeline expansions and gas processing projects.

African investors are entering the South American market equipped with valuable experience garnered from offshore and LNG developments in countries such as Congo, Nigeria, Cameroon, and Mozambique. Their expertise particularly shines in areas like floating LNG technology and gas commercialization strategies.

The African Energy Chamber has been actively involved in developing bilateral engagement frameworks designed to connect Latin American stakeholders with African governments, national oil companies, and private-sector energy firms. These initiatives aim to foster deeper cooperation and understanding between the regions. Notably, the AEC has been involved in cooperation efforts that include Petróleos de Venezuela (PDVSA) and Venezuela’s Ministry of Hydrocarbons, alongside Brazilian energy stakeholders, focusing on upstream investment and infrastructure development.

Both Africa and South America continue to place a high priority on energy sovereignty, the implementation of robust local content policies, and the pursuit of long-term hydrocarbon development strategies. These shared priorities create fertile ground for enhanced South-South cooperation, particularly within the offshore oil, LNG, and infrastructure sectors.

The Deputy Prime Minister characterized the long-standing partnership between the two energy giants as a definitive bright spot within the broader economic framework of Vietnam-Russia relations. This diplomatic engagement serves as a direct implementation of high-level agreements previously established between Russian President Vladimir Putin and the General Secretary of the Communist Party of Vietnam Central Committee and State President To Lam, aimed at fortifying the Comprehensive Strategic Partnership between the two nations.

The dialogue between Zarubezhneft, the Vietnamese Ministry of Industry and Trade, and Petrovietnam is expected to yield more effective and sustainable bilateral outcomes. Central to this success is the Vietsovpetro joint venture, which the Deputy Prime Minister highlighted as a premier model for attracting foreign investment. This venture has not only symbolized the strength of Vietnam-Russia oil and gas cooperation but has also played a pivotal role in the technical evolution of Vietnam’s domestic energy sector.

General Director Sergey Kudryashov provided an overview of the 45-year history of collaboration, noting that the partnership has remained resilient and productive. A significant milestone in oil and gas cooperation was reached in 2025 when, under the witness of both heads of state, Zarubezhneft and Petrovietnam signed protocols to extend the operational lifespan of their joint ventures in both Vietnam and Russia through 2050.

Beyond traditional extraction, the two entities are actively exploring investment opportunities in third countries. Currently, Zarubezhneft holds the position of the largest Russian supplier of coal to the Vietnamese market, further diversifying the energy portfolio. Deputy Prime Minister Tuc expressed strong support for these expansion plans, suggesting that the energy partnership should evolve to meet modern demands.

The Vietnamese government has encouraged Zarubezhneft to leverage its technical expertise in areas beyond fossil fuels. Potential sectors for future growth include offshore wind power development and renewable energy infrastructure, advanced technology transfer, electricity generation and rare earth mineral exploitation.

Santos has recently commenced oil production from the Pikka field in Alaska. This development is a cornerstone of the company’s international growth strategy. Production from the Pikka field is anticipated to increase substantially over the coming weeks, moving towards a gross output of 20,000 barrels per day. The project is on track to reach a planned plateau of 80,000 barrels per day gross by the third quarter. Santos holds a 51% stake in the Pikka Unit, operating the field in partnership with Repsol, which owns the remaining 49%.

Furthermore under the oil and LNG production expansion strategy, Santos gave the green light earlier this month to a substantial natural gas project expansion in Papua New Guinea. This brownfield project involves an investment of approximately $160 million net by Santos. The expansion will connect the Agogo Production Facility to the existing PNG LNG gas pipeline through the construction of a new 19-kilometer pipeline and two additional wells, alongside necessary facility modifications. The total gross capital expenditure for this project is estimated at $400 million over a three-year period. Upon completion, the project is expected to enhance production capacity by approximately 135 million cubic feet per day, with Santos’ net share contributing roughly 54 million cubic feet per day.

Domestically, Santos will concentrate its efforts on oil and LNG production expansion in two primary basins: the Beetaloo and Bedout basins. The company plans to leverage existing infrastructure within these regions to enhance both the scale and profitability of its operations. This approach aims to maximize efficiency and returns. Additionally, Santos will direct investments towards the Cooper Basin, specifically targeting the Moomba Central fields as part of its ongoing production ramp-up initiatives.

The Immediate Aftermath: A Production Surge and Price Volatility

The most immediate and visceral impact of a UAE exit from OPEC would be felt in the price of crude oil. Freed from the constraints of the cartel’s production quotas, ADNOC would be incentivized to unleash its full production capacity to maximize revenue and capture market share. With a current capacity of over 4 million barrels per day (bpd) and a clear strategy to reach 5 million bpd by 2027, the UAE could single-handedly introduce a tidal wave of new supply into the global market.

This scenario would likely trigger a dramatic price war, reminiscent of the brief but brutal clash between Saudi Arabia and Russia in early 2020. The market’s delicate supply-demand balance, already precarious, would be shattered.

• Price Collapse: The influx of several hundred thousand, and potentially over a million, additional barrels per day would create a significant supply glut, driving Brent and WTI crude prices sharply downward.
• Increased Volatility: The breakdown of coordinated action would inject unprecedented uncertainty into the market. Traders and investors would grapple with a new paradigm where major producers act purely on national interest, leading to wild price swings.
• Pressure on High-Cost Producers: A sustained period of low prices would squeeze the margins of higher-cost producers, particularly in US shale basins, Canadian oil sands, and deepwater offshore projects. This could lead to a wave of bankruptcies, consolidation, and shelved investment plans.

The strategic rationale for the UAE is clear: its low cost of production (among the lowest in the world) means it can remain profitable even at price points that would cripple other nations. The fallout from the UAE’s exit from OPEC would, therefore, create a clear schism between low-cost Gulf producers and the rest of the world.

Reshaping Alliances: The New Geopolitical Landscape of Oil

Beyond the numbers, the UAE exit from OPEC would fundamentally alter the geopolitical architecture of the energy world. OPEC’s power has never just been economic. It has been a vehicle for projecting the collective political influence of its members, with Saudi Arabia firmly in the driver’s seat. The departure of the cartel’s third-largest producer would critically undermine this structure.

The weakening of OPEC would be the primary consequence. The loss of the UAE’s production capacity and moderating influence would diminish the organization’s ability to effectively manage the market. This could render the OPEC+ alliance, which includes Russia and other non-OPEC partners, largely ineffective. Russia might see an opportunity to forge new, more flexible arrangements, potentially even with an independent UAE.

This move would simultaneously elevate the UAE’s individual standing on the global stage. No longer bound by collective decision-making, Abu Dhabi could pursue an entirely independent energy foreign policy, building bilateral relationships with key consumer nations like China, India, and Japan. It could offer them long-term supply contracts with stable, predictable volumes, positioning itself as a more reliable partner than a politically-driven cartel. The consequences of the UAE’s exit from OPEC would thus extend deep into diplomatic corridors, forcing nations to recalibrate their relationships across the Middle East.

Ripple Effects Across the Energy Value Chain

The shockwaves from a UAE exit from OPEC would not be contained to upstream producers and national treasuries. They would ripple through every segment of the oil and gas industry, creating distinct sets of winners and losers.

• Upstream: As mentioned, high-cost exploration and production (E&P) companies would face an existential threat. Capital expenditure would be slashed, and long-term project sanctions would become far more difficult to justify in a world of lower, more volatile prices.
• Midstream: This sector could experience a boom. An all-out production push would create immense demand for storage facilities as a supply glut builds. Similarly, the tanker market would benefit from the need to move millions of extra barrels from the Persian Gulf to consumers in Asia, Europe, and the Americas. Pipelines in consuming regions would also see higher, more consistent throughput.
• Downstream & Petrochemicals: This segment would be a clear winner. Refiners would see their primary feedstock, crude oil, become significantly cheaper, leading to a dramatic expansion in gross refining margins. The same logic applies to the petrochemical industry, which uses oil and gas derivatives like naphtha as feedstock. Lower input costs would boost profitability and could spur investment in new crackers and derivative plants.

This internal industry disruption highlights how a strategic decision at the cartel level can fundamentally re-engineer the economics of the entire supply chain.

A Catalyst for the Energy Transition

Perhaps the most complex and debated consequence of a UAE exit would be its impact on the global energy transition. The outcome is paradoxical, with compelling arguments on both sides.

On one hand, a prolonged period of low and volatile oil prices could accelerate the transition. The extreme uncertainty would make multi-billion dollar, decade-long investments in new fossil fuel projects appear far riskier. Capital may instead flow towards the perceived safety and predictable returns of renewable energy projects like wind and solar, which are insulated from commodity price swings. Major international oil companies (IOCs), facing diminished returns from their core business, might be forced to pivot more aggressively into low-carbon energy.

Conversely, an era of cheap oil could decelerate the transition. Inexpensive gasoline and diesel would reduce the economic incentive for consumers and businesses to switch to electric vehicles or invest in energy efficiency. For developing nations in Asia and Africa, cheap and abundant crude oil would be a powerful engine for economic growth, pushing decarbonization goals further down the priority list. A thorough analysis of the UAE’s exit from OPEC must therefore acknowledge this double-edged sword: it could either cripple the financing of future oil projects or entrench global fossil fuel dependency for another generation.

Conclusion

The departure of the United Arab Emirates from OPEC would be far more than a simple exit from an organization. It would be the end of an era. It would shatter the decades-old paradigm of collective supply management and usher in a new, more competitive, and unpredictable age of every producer for themselves. The immediate consequences, a price war, heightened volatility, and immense pressure on high-cost producers, are clear. But the deeper implications, from the reconfiguration of global alliances to the re-engineering of the industry’s value chain and the uncertain impact on the energy transition, are even more profound. While the UAE remains a member for now, the mere plausibility of this scenario serves as a stark reminder that the foundations of the global oil market are not as stable as they appear. Industry leaders must begin planning for a future where old alliances crumble and new, independent powers rise.

The comprehensive full-field Phase 3 development is set to substantially augment production capabilities. Envisioned under this phase is an increase in oil output from the current 60,000 barrels per day to a target of 150,000 barrels per day. Simultaneously, natural gas production is slated to rise from 80 million cubic feet per day to 200 million cubic feet per day. Crucially, all natural gas generated by the Baleine project phase 3 development will be directed towards meeting the domestic energy demands of Côte d’Ivoire. This strategic allocation is expected to bolster the country’s electricity generation capacity and provide vital support for its ongoing industrial expansion.

The Baleine project phase 3 development plan includes the integration of a new floating production, storage, and offloading (FPSO) unit. This unit is being engineered to uphold stringent standards of operational efficiency and safety, while simultaneously minimizing its environmental footprint. This approach aligns with global efforts towards more sustainable energy production.

This third stage of development continues the successful strategy of phased and fast-track implementation, a model that has defined the initial two phases of the Baleine project. This methodology has facilitated the commencement of early production, effectively optimizing costs and capitalizing on the existing infrastructure.

“Baleine is a testament to Eni’s exploration and production model, built on excellence in exploration activities, the ability to develop projects through a fast-track and phased approach, and a consistent commitment to sustainability, in continuous dialogue with the host country. This project reflects our commitment to strengthening energy security, supporting local economic development and advancing a lower-carbon energy future,” said Claudio Descalzi, Chief Executive Officer of Eni.

This approach for oil shipments is particularly notable as other Middle Eastern producers and Western commodity traders have also sought methods to move cargoes through Hormuz during nearly three months of conflict. However, these entities often rely on leased tankers, making them subject to the risk tolerance of the vessel owners. In contrast, Adnoc utilizes vessels controlled by Navig8, a company in which its shipping and logistics arm holds a majority stake, and Wanhua Chemical Group, a joint-venture partner. The fleet includes crude and clean petroleum product tankers, as well as gas carriers.

The proactive measures taken by Adnoc for oil shipments underscore the pressing need for oil producers to deliver supplies to the market, partly due to the limitations of their storage capacity. The United Arab Emirates’ departure from the Organization of the Petroleum Exporting Countries (OPEC) in May also signals an increased willingness for Adnoc to explore more assertive strategies for exporting its oil.

The proximity of Adnoc’s loading points to Hormuz is a significant advantage. Crudes like Upper Zakum are loaded at Zirku Island, while naphtha and liquefied petroleum gas are sourced from Adnoc’s extensive refinery complex at Ruwais. These shorter transit routes allow for a rapid turnaround, with return journeys taking approximately one week. Adnoc has also managed to export at least three liquefied natural gas (LNG) cargoes through Hormuz using dark transits, with the most recent observed heading towards western India over the past weekend, according to ship-tracking information.

Satellite imagery suggests that LNG tankers have been docking at Das Island, Adnoc’s export facility within the Persian Gulf, for at least a month, despite no vessels broadcasting their positions in the vicinity. For gas departures, empty tankers approach the eastern entrance of the Strait of Hormuz, near the Fujairah anchorage, before ceasing signal transmission. They resume broadcasting their location only after clearing the strait and entering the Gulf of Oman.

Sheikha Tamadher Khaled Al-Ahmad Al-Jaber Al-Sabah, Director of Public Relations and Petroleum Media at the Ministry of Oil, highlighted Kuwait’s increasing commitment to expanding the utilization of natural gas in electricity generation. This strategic initiative aims to improve energy efficiency, enhance environmental performance, and optimize overall fuel consumption across the nation. A central component of this strategy involves the development of robust infrastructure.

Key infrastructure projects, notably the liquefied natural gas (LNG) import facilities in the Al-Zour area, were recognized as a critical element in supporting the country’s power and water generation needs. These facilities are designed to strengthen the resilience and sustainability of Kuwait’s energy system, aligning with the growing domestic demand for electricity and energy. Such developments are crucial for aligning with global transformations in the energy sector and fostering a more efficient and sustainable energy mix.

The panel also addressed the dynamic global energy market. Wael Abdel-Moaty, a gas industry expert at the Arab Energy Organization, noted significant structural shifts in the global energy market during the first quarter of 2026. These shifts were partly attributed to disruptions in liquefied natural gas shipments navigating the Strait of Hormuz. This period also saw a surge in investment and contracting activity, driven by heightened international concerns regarding supply security and the imperative for energy diversification.

The United States solidified its position as the leading global natural gas exporter, capturing approximately 29 percent of the market share, largely benefiting from the disruptions affecting exports through the Strait of Hormuz. Abdel-Moaty emphasized the sensitivity of LNG trade to strategic maritime routes, stating that interruptions to navigation through the Strait impacted nearly 19 percent of global LNG trade. This underscored the vital role of maritime security in maintaining market stability.

In contrast, Arab countries experienced a decline in LNG exports exceeding 24 percent during the first quarter of 2026. This reduced the region’s market share to below 20 percent, a notable decrease from its previous standing of around 25 percent, following recent geopolitical developments. These shifts highlight the complex interplay of global events on energy trade flows.

Gas-importing nations implemented various strategies to navigate supply fluctuations. Countries like India prioritized essential gas-consuming sectors, including residential use and transportation. Meanwhile, Japan and South Korea eased restrictions on alternative energy sources, such as coal, to alleviate pressure on their gas consumption. The European Commission advised a cautious approach to managing stockpiling efforts to prevent additional price pressures.

Despite these measures, the spot market for LNG experienced a significant surge. Prices climbed by over 60 percent in March 2026 compared to February, reaching $18 per million British thermal units (MMBtu). The Arab Energy Organization forecasts that global LNG supplies will reach approximately 435 million tons in 2026, representing a modest growth of only 1 percent compared to earlier projections of 8 percent. This downward revision is attributed to concerns over supply shortages and the risks associated with strategic shipping routes.

The discussion also turned to hydrogen, a critical component of the global energy transition. Abdel-Moaty reported that global political momentum continues to accelerate, with around 65 countries now having adopted national hydrogen strategies. These strategies represent a significant portion of the global economy, approximately 85 percent, and account for about 80 percent of global carbon dioxide emissions.

The session was attended by representatives from the Ministry of Electricity, Water and Renewable Energy, the Environment Public Authority, the Arab Energy Organization, and students from Kuwait University’s College of Engineering and Petroleum, signifying a broad engagement with these critical energy topics.