The Traditional Hydrogen Dilemma in Industrial Decarbonization

To appreciate the impact of clean hydrogen, one must first understand the historical role of hydrogen within a refinery. Hydrogen is the circulatory system of the refining process. It is used extensively in hydrotreating to remove impurities like sulfur from crude oil and in hydrocracking to break down heavy molecular chains into high-value products like gasoline, diesel, and jet fuel. Historically, this hydrogen has been produced through Steam Methane Reforming (SMR), a process that relies on natural gas as a feedstock. While SMR is cost-effective and highly efficient, it is also carbon-intensive, releasing significant amounts of carbon dioxide into the atmosphere. This grey hydrogen is currently responsible for a massive portion of a refinery’s direct carbon footprint.

The challenge for industrial decarbonization is that refineries cannot simply stop using hydrogen; in fact, as crude oil quality declines and environmental regulations for fuels tighten, the demand for hydrogen actually increases. This creates a paradox where the industry needs more of a resource that is a major contributor to its emissions profile. This is where green hydrogen integration enters the narrative. By replacing grey hydrogen with hydrogen produced via the electrolysis of water using renewable energy, refineries can eliminate a substantial percentage of their Scope 1 and Scope 2 emissions without compromising their core output.

Technical Pathways for Green Hydrogen Integration

Integrating green hydrogen into existing refinery operations is far more complex than simply swapping one gas for another. It requires a sophisticated understanding of both chemistry and logistics. The primary technology at play is the electrolyzer, which uses electricity to split water into hydrogen and oxygen. For a refinery to successfully implement this, it must manage the scale and intermittency of renewable energy sources like wind and solar. Unlike a steady stream of natural gas, renewable energy fluctuates, meaning the hydrogen refinery of the future must incorporate significant storage solutions or be paired with massive, dedicated renewable energy parks to ensure a constant supply of pressurized hydrogen for sensitive refining units.

There are two primary types of electrolyzer technologies currently being evaluated for large-scale sustainable refining: Proton Exchange Membrane (PEM) and Alkaline electrolysis. PEM electrolyzers are often favored for their ability to respond quickly to the fluctuations of renewable power, making them ideal for direct integration with wind or solar farms. Alkaline electrolyzers, while more mature and generally less expensive at scale, typically require a more stable power input. Choosing between these technologies—or utilizing a hybrid approach—is a critical decision for engineers tasked with refinery decarbonization. The goal is to ensure that the hydrogen supply remains as reliable as the SMR units they are intended to replace or supplement.

Optimizing Refinery Operations for Low-Carbon Fuels

The drive for clean hydrogen is closely linked to the growing market for low-carbon fuels. As the aviation and maritime industries face increasing pressure to reduce their carbon footprints, the demand for Sustainable Aviation Fuel (SAF) and renewable diesel is skyrocketing. Producing these fuels requires significantly more hydrogen than traditional fossil-based fuels because bio-based feedstocks often have a high oxygen content that must be removed through hydrodeoxygenation. Green hydrogen integration provides the necessary chemical bridge to turn vegetable oils, waste fats, and cellulosic biomass into drop-in fuels that are compatible with existing engines.

Furthermore, the integration process allows refineries to diversify their product portfolios. A refinery that masters the production and use of green hydrogen can pivot from being a purely petroleum-based facility to a multi-energy hub. This transition is essential for the long-term viability of the industry. By producing low-carbon fuels, refineries can maintain their relevance in a world where electric vehicles are reducing the demand for traditional gasoline. The hydrogen itself can also become a product for sale, serving local transport fleets or being injected into natural gas grids, thereby deepening the facility’s role in the regional hydrogen economy.

Overcoming the Economic and Infrastructure Hurdles

While the environmental case for green hydrogen integration is undeniable, the economic hurdles remain significant. Currently, the cost of producing green hydrogen is substantially higher than that of grey hydrogen. This price disparity is driven by the capital expenditure required for high-capacity electrolyzers and the operational costs associated with securing a consistent supply of renewable electricity. However, the gap is narrowing. Economies of scale, advancements in electrolyzer manufacturing, and the falling cost of solar and wind power are all contributing to a downward trend in green hydrogen pricing.

Policy frameworks play an indispensable role in bridging this economic gap. In many regions, carbon pricing and subsidies for renewable energy projects are making refinery decarbonization a more attractive investment. Governments are recognizing that without the active participation of heavy industry, net-zero targets will remain out of reach. Tax credits, such as those seen in recent North American and European legislation, provide the financial cushion necessary for refineries to take the leap into large-scale green hydrogen integration. These incentives do not just offset costs; they de-risk the transition for stakeholders and encourage the long-term capital commitments required for such massive infrastructure projects.

Scaling Up for Global Impact

The scale of integration required is staggering. A mid-sized refinery might require hundreds of megawatts—or even gigawatts—of electrolyzer capacity to fully replace its SMR units. This scale necessitates a complete overhaul of on-site utilities. Beyond the electrolyzers, refineries must invest in water purification systems, as the electrolysis process requires high-purity water, and heat management systems to handle the thermal energy produced during the splitting of water molecules.

Integration also demands a rethink of inside the fence versus outside the fence operations. Some refineries are choosing to build and operate their own electrolyzer plants, while others are entering into over-the-fence agreements with third-party utility providers who deliver the hydrogen via pipeline. This latter model allows the refinery to focus on its core competency of fuel production while leveraging the expertise of specialized hydrogen producers. Regardless of the business model, the physical footprint of the refinery will expand, requiring new safety protocols and a workforce trained in the nuances of high-pressure hydrogen handling and renewable energy management.

Sustainable Refining and the Circular Economy

The shift toward sustainable refining goes beyond just emissions reduction; it is about embracing a circular economic model. For instance, the byproduct of electrolysis is pure oxygen. In a traditional setup, this might be vented into the atmosphere, but a truly integrated hydrogen refinery can find value in this stream. The oxygen can be used to enrich the air in fluid catalytic cracking units or used in wastewater treatment facilities, further improving the overall efficiency of the site.

Additionally, the captured carbon from existing processes, if combined with clean hydrogen, can be used to create synthetic fuels or e-fuels. This process, known as Power-to-X, represents the ultimate frontier of industrial decarbonization. It allows for a closed-loop system where carbon is reused rather than released, and the energy carrier is entirely carbon-neutral. While still in its infancy, the pilot projects currently underway at major global refineries are proving that this level of integration is technically feasible and holds the key to a future where liquid fuels are no longer synonymous with environmental degradation.

Navigating the Social and Regulatory Landscape

The transition to green hydrogen integration also carries significant social and regulatory implications. As refineries are often major employers in their local communities, the move toward greener technologies must be managed as a just transition. This involves reskilling workers and ensuring that the new hydrogen-based economy provides the same level of economic stability as the oil era. Regulators are also looking at the life-cycle analysis of hydrogen, ensuring that the electricity used is truly additional and not simply diverted from the existing grid, which could inadvertently increase overall emissions.

In Europe, the Renewable Energy Directive (RED II and III) has set strict criteria for what constitutes green hydrogen, forcing refineries to be meticulous in their sourcing and documentation. Similar standards are being developed globally, creating a standardized market for clean hydrogen. For refinery operators, staying ahead of these regulations is not just about compliance; it is about securing a competitive advantage in a market where consumers and corporate partners are increasingly demanding transparency regarding the carbon intensity of their fuel.

Synthesizing the Path Forward

The integration of green hydrogen into refining operations is not a singular event but a multi-decade journey of transformation. It begins with small-scale pilots that prove the reliability of electrolyzers within the high-stakes environment of a refinery. It then moves into larger demonstrations where green hydrogen is blended with grey hydrogen to gradually lower the carbon intensity of the final products. Finally, it culminates in the full-scale hydrogen refinery, an industrial facility that operates in harmony with the planet’s ecological limits.

As we look toward the middle of the century, the refineries that thrive will be those that viewed refinery decarbonization not as a burden but as a catalyst for innovation. The movement toward green hydrogen integration is essentially a commitment to the longevity of the industry. It ensures that the vital role refineries play in the global economy—providing the energy and materials necessary for society to function—can continue in a world that can no longer afford the cost of carbon. Oil & Gas Advancement notes that by embracing low-carbon fuels and the broader hydrogen economy, the refining sector is proving that even the most established industrial giants can evolve, paving the way for a cleaner, more resilient energy future.

The Strategic Importance of Zero Routine Flaring in the Energy Transition

Understanding the distinction between routine and non-routine flaring is essential for appreciating the scope of the Zero Routine Flaring by 2030 initiative. Routine flaring occurs during normal production operations when gas is produced alongside oil but is not used on-site or sent to market. In contrast, non-routine flaring remains necessary for safety during emergencies, maintenance, or equipment failure. The global push targets the former, which represents a significant loss of energy and a major source of carbon emissions. For producers, committing to ZRF is a declaration of intent to modernize. It signals to investors and regulators that a company is serious about its ESG targets and is actively working to minimize the carbon intensity of its operations.

The scale of the challenge is significant. According to the World Bank’s Global Gas Flaring Reduction Partnership (GGFR), billions of cubic meters of natural gas are flared annually, enough to power millions of homes. When this gas is flared, it releases carbon dioxide into the atmosphere. Perhaps more critically, inefficient flaring leads to the release of unburnt methane—a greenhouse gas with a global warming potential significantly higher than CO2 over a twenty-year period. Consequently, zero routine flaring is now recognized as one of the most effective levers for immediate methane reduction in the energy sector.

Flare Gas Recovery: The Primary Technological Frontier

To meet 2030 sustainability goals, the industry is increasingly relying on flare gas recovery (FGR) systems. These technologies act as the first line of defense against emissions by capturing gas that would otherwise be sent to the flare header. An FGR system typically consists of compression units, liquid separators, and control systems designed to handle the variable flow and composition of associated gas. By capturing this gas, producers can repurpose it for on-site power generation, reinject it into reservoirs for enhanced oil recovery, or process it for sale.

The sophistication of modern FGR units has increased dramatically. Older systems often struggled with the corrosive nature of some associated gases or the fluctuating pressures inherent in upstream operations. Today’s modular, skid-mounted FGR systems are designed for rapid deployment even in remote or offshore environments. These units utilize advanced compression technologies, such as liquid ring compressors or dry screw compressors, which are capable of handling ‘wet’ gas and varying flow rates with high reliability. The integration of these systems directly reduces the carbon emissions profile of a facility while simultaneously recovering a valuable resource that was previously treated as waste.

Gas Utilization Strategies: Beyond the Pipe

One of the greatest hurdles to zero routine flaring has traditionally been geography. Many upstream oil and gas assets are located in remote regions where constructing a pipeline to transport associated gas to a central processing plant is economically unfeasible. In these scenarios, the focus shifts to localized gas utilization. This virtual pipeline approach transforms the captured gas into a variety of useful products right at the wellhead.

One of the most promising avenues is the conversion of gas to power. Small-scale gas turbines or reciprocating engines can use captured flare gas to generate electricity for the production facility itself, reducing the need for diesel generators and further lowering the site’s carbon footprint. Excess power can sometimes even be fed back into the local grid, turning an environmental liability into a revenue stream. Additionally, micro-LNG and compressed natural gas (CNG) technologies have matured to the point where they can be deployed at the source. These modular plants liquefy or compress the gas so it can be transported via truck to nearby markets or industrial consumers.

Another innovative utilization method involves using the gas for on-site industrial processes, such as heating or as a feedstock for chemical production. In some regions, producers are even exploring ‘gas-to-bins’ solutions, where captured gas powers mobile data centers or cryptocurrency mining units located directly at the well site. While unconventional, these methods provide a high-value use for gas that would otherwise be flared, effectively bridging the gap until permanent infrastructure can be established.

Digitalization and Real-Time Emissions Control

The success of any zero routine flaring strategy depends on the ability to accurately measure and monitor emissions. You cannot manage what you do not measure, and for many years, flaring volumes were estimated rather than precisely tracked. Digitalization is changing this through the deployment of advanced sensors, satellite monitoring, and AI-driven analytics. Modern emissions control systems provide real-time data on flare combustion efficiency, allowing operators to adjust parameters instantly to ensure that if flaring must occur for safety, it is as clean as possible.

IoT-enabled sensors placed throughout the production chain can detect leaks and identify ‘thieving’ valves that allow gas to escape into the flare system unnoticed. Furthermore, satellite-based observation has become a powerful tool for global transparency, providing independent verification of flaring activity across the world. For producers, these digital tools are essential for reporting against ESG targets and proving to stakeholders that they are meeting their methane reduction commitments. AI algorithms can also predict flaring events by analyzing pressure and flow trends, allowing operators to take preemptive action to divert gas into recovery systems before flaring becomes necessary.

The Role of Carbon Markets and Economic Incentives

While the environmental case for zero routine flaring is clear, the economic case has historically been more complex. The capital expenditure required for flare gas recovery and gas utilization can be substantial. However, the landscape is shifting as carbon pricing mechanisms and methane taxes become more common. In many jurisdictions, the cost of emitting carbon is rising to the point where investing in ZRF technology offers a compelling return on investment.

Furthermore, the ‘green premium’ on low-carbon energy is creating new market opportunities. Producers who can certify that their oil is produced with zero routine flaring may find their products more attractive to buyers who are themselves under pressure to decarbonize their supply chains. This economic alignment is a critical component of reaching 2030 targets. When the cost of flaring—both in terms of lost resource value and carbon penalties—exceeds the cost of recovery and utilization, the transition to ZRF becomes a self-sustaining business strategy.

Overcoming Operational and Economic Barriers in Upstream Oil and Gas

Despite the availability of technology, several barriers to zero routine flaring remain. Infrastructure is the most prominent. In many developing oil-producing regions, the lack of a national gas grid makes it difficult to find a home for recovered gas. Overcoming this requires not only technological innovation but also policy intervention. Governments play a vital role by creating regulatory frameworks that encourage investment in gas gathering systems and by removing subsidies that might make flaring artificially cheap.

Regulatory clarity is also essential for gas utilization. In some areas, the legal status of associated gas is ambiguous, making it difficult for third-party companies to invest in onsite power generation or micro-LNG projects. By streamlining the permitting process and providing clear guidelines for gas ownership and sales, regulators can unlock the private capital needed to deploy ZRF technologies at scale. Collaboration between the public and private sectors is the only way to ensure that the necessary infrastructure is built in time to meet the 2030 deadline.

ESG Targets and the Future of Upstream Oil and Gas

The commitment to zero routine flaring has become a benchmark for excellence in the upstream oil and gas industry. Investors are increasingly using flaring intensity as a key metric when evaluating the sustainability of energy companies. Consequently, firms that lag behind in adopting emissions control technologies may find themselves facing higher costs of capital or divestment.

As we look toward the 2030 sustainability goals, the focus is expanding beyond just routine flaring. The industry is beginning to look at near-zero flaring, where even safety and maintenance flaring are minimized through better equipment design and predictive maintenance. The ultimate goal is a closed-loop system where every molecule of gas is accounted for and used productively. This evolution represents a complete reimagining of the upstream facility, from a site of extraction to a sophisticated energy hub that maximizes resource efficiency and minimizes environmental harm.

Achieving a Sustainable Balance

The journey to zero routine flaring is a testament to the ingenuity and resilience of the energy sector. By integrating flare gas recovery, advancing methane reduction, and pioneering new gas utilization techniques, producers are demonstrating that the transition to a low-carbon future is achievable. The technologies required to meet the 2030 targets are no longer experimental; they are proven, scalable, and increasingly economical.

As the industry continues to innovate, the focus must remain on the rapid deployment of these solutions across all geographies, not just in the most developed markets. The elimination of routine flaring is one of the most significant contributions the oil and gas industry can make to the global effort to combat climate change. Oil & Gas Advancement believes that by turning a waste product into a source of energy, the sector is not only reducing its carbon footprint but also contributing to global energy security and economic growth. The path to 2030 is steep, but with the right combination of technology, policy, and persistence, zero routine flaring is a goal that is firmly within reach.

Outlining the objectives of the initiative, Handanović said, “We are working on concrete steps to launch a one billion euro project through which we will strengthen and modernize the internal gas infrastructure, institutional capacities and provide support for reform activities with the World Bank.”

“In the first phase, we will build the first section of the Niš-Velika Plana gas pipeline. The new gas pipelines that we build through this project will enable us to use the full potential of gas interconnections with neighboring countries, which means greater energy security, as well as strengthening our position as a transit country and gas hub in this part of Europe, which also brings us greater revenues. The southern and eastern parts of the country will gain greater access to gas, which is important for the development of industry and attracting investments,” she added.

Future Phases to Expand Capacity and Strengthen Project Coordination

The Minister explained that subsequent stages of the EUR 1B gas program are designed to expand the capacity of the existing natural gas transport network while also providing for the construction of compressor stations and the enlargement of underground gas storage capacities. According to her, these measures are expected to improve system security, reinforce regional connectivity, and enhance the flexibility of the overall gas system.

Discussions with the World Bank delegation also addressed the financing process and the organization of project management as preparations continue.

“The working group for project coordination will consist of representatives of the Ministry of Mining and Energy, gas sector companies “Gas Infrastructure”, “Transportgas”, “Srbijagas” and other relevant parties. Until funding is approved, this working group will coordinate the preparation and implementation of the project, so that all activities are carried out within the planned deadlines,” she said.

The meeting further reviewed the implementation timeline for the EUR 1B gas program, including the World Bank’s financing approval procedure, the establishment of a project implementation unit, and the institutional support required to advance the initiative.

The initiative took shape during discussions held between Algeria’s Minister of State and Minister of Energy, Mines and Renewable Energies Mohamed Arkab, and Matthew Harwood, Chief Executive Officer of Norwegian investment firm ICA Finance. The meeting, which included senior officials from Algeria’s energy sector, concentrated on expanding cooperation between Sonatrach and ICA Finance in areas centered on greenhouse-gas mitigation, including methane-abatement technologies, carbon capture and storage, and financing frameworks designed to support lower-carbon hydrocarbon production.

Balancing Climate Commitments with Energy Security

Both sides emphasized broad agreement on the necessity to reduce methane emissions while underscoring that international regulatory frameworks should be grounded in scientific evidence. The discussions acknowledged the need to consider the specific circumstances of hydrocarbon-producing countries and maintain the stability of global energy markets and supplies.

The talks explored opportunities to expand cooperation between Sonatrach and ICA Finance, which specializes in developing and financing methane and CO₂-reduction projects for the oil and gas sector. These discussions build upon a memorandum of understanding signed by Sonatrach and ICA Finance in 2024 to explore cooperation in areas supporting greenhouse-gas emissions reduction and cleaner hydrocarbon production.

The latest exchanges represent a transition from broad cooperation frameworks towards identifying concrete projects capable of supporting Algeria’s longer-term hydrocarbon decarbonization agenda. Algeria has increasingly positioned emissions reduction as a strategic component of its energy policy while maintaining its standing as a reliable supplier of hydrocarbons to international markets.

Algeria’s Climate Commitments and Decarbonization Strategy

Having ratified the Paris Agreement in 2016, Algeria has committed to reducing greenhouse-gas emissions by 7% by 2030 under its updated Nationally Determined Contribution. During the meeting, Minister Arkab reaffirmed Algeria’s commitment to expanding bilateral cooperation with Norway in the hydrocarbons sector, emphasizing the importance of strengthening collaboration between Sonatrach and ICA Finance.

Arkab outlined Algeria’s national climate strategy for the hydrocarbons sector, which encompasses several key initiatives:

• Reducing routine gas flaring to below 1% by 2030
• Intensifying methane-emissions mitigation programmes
• Expanding carbon capture and storage projects
• Promoting circular-economy solutions
• Accelerating the deployment of innovative low-emission technologies
• Supporting Sonatrach’s large-scale reforestation programme, which aims to plant 420 million trees.

ICA Finance’s Role in Supporting Energy Transition

ICA Finance expressed strong interest in expanding its presence in the Algerian market and supporting Sonatrach’s energy transition through innovative financing solutions, advanced emissions-reduction technologies and technical cooperation. Harwood welcomed the potential of Algeria’s hydrocarbons sector and acknowledged the efforts undertaken by both Algeria and Sonatrach to reduce carbon emissions.

According to statements from the ministry, ICA Finance reaffirmed its readiness to contribute to the hydrocarbon decarbonization partnership through financing mechanisms, technology transfer and the exchange of expertise.

During the meeting, both sides evaluated the implementation of the understandings achieved at the 19th session of the Iran-Russia Joint Economic Commission in February 2026, assessing progress across all 146 agreed clauses. Officials also examined challenges that have slowed implementation and discussed practical solutions aimed at removing those obstacles.

Paknejad said expanding cooperation in the energy sector remained a central theme of the talks, while discussions also covered Russian companies’ investment in Iran’s oil and gas fields and measures designed to address existing issues. The gas agreement was among the primary subjects considered during the meeting, reflecting the importance both countries continue to place on advancing bilateral energy cooperation.

Gas Trade Negotiations Approach Final Stage

“Agreement has been reached on the main clauses of this contract, with only two clauses remaining that require further negotiations, which we hope will be finalized in the near future,” Paknejad said.

The progress surrounding the gas agreement was highlighted as a key outcome of the discussions, with both sides continuing efforts to complete the remaining provisions. According to the Iranian Oil Minister, resolving outstanding matters is expected to support the broader implementation of the understandings already reached through the Joint Economic Commission and strengthen ongoing cooperation between the two countries.

Russia and Iran Agree to Remove Cooperation Barriers

Russia’s Energy Minister, Sergei Tsybulyov, also confirmed that Tehran and Moscow had agreed to accelerate efforts to eliminate barriers affecting cooperation between companies in both countries. He stated that, despite recent special conditions, cooperation in the energy sector has continued to deliver satisfactory results.

Tsybulyov said regular meetings are held with Iran’s Oil Minister and described the working relationship between the two countries as very positive. He explained that the implementation of agreements reached during the 19th Joint Economic Commission was reviewed in detail, with important decisions taken on every issue under consideration.

He further stated that both governments had agreed to address and resolve all outstanding matters involving Iranian and Russian companies as quickly as possible. Tsybulyov also expressed hope that Iran’s Oil Minister would soon visit Moscow to help accelerate the cooperation process, while reiterating his satisfaction with the progress achieved despite recent developments.

Based on estimates that place South African oil demand at 600,000 barrels per day, the proposed reserve would total about 36 million barrels, representing an asset worth billions of dollars. In addition to the state-held reserves, the draft policy would require licensed wholesalers and importers to maintain inventories equivalent to 21 days of demand. Oversight and management of these strategic oil reserves would fall under the state-owned South African National Petroleum Co.

According to the Department of Mineral and Petroleum Resources, the National Treasury and the SANPC will develop financing mechanisms and instruments for the financing and guaranteeing strategic petroleum stocks.

Regional efforts gain momentum as governments strengthen fuel security

South Africa’s last major emergency stockpiling initiative dates back to the 1970s after the United Nations imposed sanctions on the country over its policy of institutionalized racial segregation. Those circumstances resulted in the construction of the 45 million-barrel Saldanha Bay storage hub on the Atlantic coast.

More recently, concerns over supply security and higher prices linked to the US-Israeli war on Iran have restored the facility’s original purpose of serving as a safeguard against severe oil-supply shortages. The conflict across the Middle East contributed to higher global fuel prices while prompting countries to seek alternative sources of supply. Across Africa, several governments responded by reducing taxes and allocating budget resources to help contain fuel costs.

Alongside these short-term measures, governments are increasingly pursuing infrastructure investments designed to strengthen control over fuel supplies and reduce dependence on trading companies. Morocco announced in June 2026 that it will invest $641 million in the development of fuel-storage facilities, while Uganda plans to expand a state-owned terminal to improve supply stability. Ghana is also preparing to increase the use of domestic crude in its refineries.

At the same time, billionaire Aliko Dangote has accelerated projects across the continent after his Nigerian refinery increased production during the Persian Gulf conflict. These initiatives include constructing another refinery of the same design in Kenya as well as developing storage facilities in The Gambia.

The talks centered on expanding cooperation in natural gas, increasing the involvement of Egyptian companies in Jordan’s energy infrastructure projects, and identifying joint investment opportunities in mining, with a particular focus on phosphate production and downstream mineral industries.

Badawi said Egypt is keen to deepen cooperation with Jordan in both the energy and mining sectors, building on the two countries’ longstanding partnership in natural gas. As part of the discussions, both sides also reviewed ways to expand the presence of Egyptian petroleum companies within Jordan’s energy sector. Companies including Fajr Jordan Egyptian, Petrojet, Enppi, and Gas Misr are already active in the Jordanian market, while Eprom, Town Gas, and Modern Gas are expected to participate in future projects related to natural gas distribution, operations, and maintenance.

Joint Technical Working Groups to Advance Future Implementation

Al-Kharabsheh said cooperation between Jordan and Egypt has become a model for Arab energy integration, noting that previous joint projects have laid a strong foundation for expanding strategic partnerships that deliver long-term economic benefits for both countries. He also announced that Jordan is approaching the signing of agreements with two Egyptian companies to carry out natural gas distribution projects in the industrial cities of Ma’an and Al Muwaqqar.

These projects are expected to complement the continuing expansion of gas networks in Mafraq and Zarqa, supporting broader use of natural gas across Jordan’s industrial sector and further strengthening energy cooperation between the two nations.

The meeting marked the beginning of Badawi’s visit to the Jordanian capital and was attended by Egypt’s Ambassador to Jordan Khaled El Abyad, Yasser Salah El Din, Chairperson of Fajr Jordan Egyptian Natural Gas Company, Mohamed El Bagoury, Head of the Legal Affairs Department at Egypt’s Ministry of Petroleum and Mineral Resources, along with senior officials from both countries.

At the conclusion of the discussions, the two ministers agreed to establish joint technical working groups to follow up on the proposals presented during the meeting. These groups will develop implementation mechanisms covering natural gas, mining, value-added industries, infrastructure development, and investment partnerships between Egyptian and Jordanian companies, creating a structured framework for advancing future bilateral initiatives.

The meeting built upon a series of high-level engagements that have strengthened the Korea-UAE strategic partnership in recent months. These exchanges included the Korean President’s state visit to the UAE in November 2025, Minister Kim’s visit in June 2026, and the visit by the Presidential Special Envoy for Strategic Economic Cooperation in March 2026. Over this period, cooperation has steadily expanded across several strategic sectors, including crude oil, naphtha, nuclear power, energy infrastructure, and advanced industries.

With Minister Al Jaber visiting Korea, both sides reviewed the progress achieved so far and exchanged views on sustaining momentum while exploring additional collaboration in areas such as AI and energy infrastructure.

Agreement Signed to Strengthen Crude Oil Supply Chain Security

A major outcome of the meeting was the signing of a strategic cooperation agreement between MOTIR and ADNOC covering the crude oil supply chain. The agreement establishes a framework for cooperation on stable crude oil supply, emergency response measures, and joint stockpiling. It is designed to strengthen crude oil security cooperation and ensure reliable collaboration during periods of disruption, including conflicts in the Middle East. Both sides expect the new framework to further reinforce bilateral cooperation in energy and resource security while supporting a dependable crude oil supply relationship.

Beyond energy security, the ministers also explored opportunities to collaborate on AI adoption in the refining and petrochemical industries, where both countries have established capabilities. Minister Kim introduced Korea’s AI transformation project for the petrochemical industry in the Ulsan-Mipo Industrial Complex and highlighted examples of Korean refining and petrochemical companies implementing AI technologies.

He also pointed to the similarities between ADNOC’s strategy of expanding AI across all crude oil-related operations and Korea’s Manufacturing AI Transformation (M.AX) policy, proposing that companies and institutions from both countries identify practical joint cooperation projects.

Infrastructure Cooperation and Future Industrial Opportunities

The discussions also addressed energy infrastructure initiatives currently underway in the UAE, including projects to expand oil and gas storage and transport infrastructure designed to bypass the Strait of Hormuz. Minister Kim noted that Korean companies are evaluating multiple forms of participation in these developments, including EPC contracts, and requested the UAE’s consideration and support for their involvement in future projects.

“Although the situation in the Middle East is changing, securing stable supply chains for critical resources remains one of the most important tasks for Korea’s economic security. Korea needs to further strengthen its strategic partnership with the UAE, a major energy supplier,” Minister Kim said. “We also need to broaden the scope of cooperation beyond critical resource supply chains by exploring new possibilities and opportunities in advanced industries such as AI. Building on this meeting, MOTIR will work closely with the UAE to deliver concrete outcomes,” he added.

Strategic Expansion of Mediterranean Gas Resources

Currently, the energy requirements of the country are primarily met by several offshore gas fields located along the coast, with the Tamar site serving as a primary source for internal use. Meanwhile, the Leviathan site, situated approximately 130 kilometers offshore, handles the majority of the nation’s energy exports, which are largely directed toward Egypt and Jordan.

The newly announced Mediterranean natural gas exploration initiative will be executed in three distinct phases and is expected to span approximately one year. Chevron, the current operator of the major existing fields, has been granted permission to participate in this process as part of a joint consortium.

Production Requirements and Future Export Potential

Israeli law mandates a specific distribution for any new discoveries made during natural gas exploration activities. The first 50 billion cubic meters (bcm) of gas identified must be reserved exclusively for local consumption. Any volumes discovered beyond that threshold will be divided between domestic needs and international markets. Current estimates from the Petroleum Commissioner Chen Bar Yoseph suggest that up to 400 bcm of gas may still be undiscovered in these offshore gas fields, which could significantly alter the current production landscape.

At present, the nation consumes 14 bcm annually and exports an equivalent amount. While there is notable interest in Mediterranean natural gas from European markets, the lack of a direct pipeline remains a logistical hurdle. However, officials suggest that if the latest search results in substantial new gas reserves, the possibility of establishing infrastructure for European supply could be revisited. This follows previous licensing successes where companies such as BP, Socar, and NewMed Energy were granted rights to explore the region’s maritime wealth.

Funding and Implementation of the Emergency Gas Reserve

The strategic gas reserve is projected to hold volumes equivalent to nearly 10% of the total natural gas storage capacity within the country. To finance this project, the German Economy Ministry stated that a levy will be placed on gas consumers. To prevent market volatility, the acquisition of gas for the reserve will be distributed over a two-to-three-year period, ensuring that the purchases do not negatively impact the price of gas.

The initial phase of injecting gas into this new emergency gas reserve is scheduled for the summer of 2027. This move is part of a broader strategy to enhance energy security and prevent potential gas shortages or sudden spikes in power prices. Currently, there is a concerted effort across Europe to replenish natural gas storage sites after a winter season that left inventories at their lowest levels in several years.

Market Trends and Import Diversification

As of early July, data shows that storage sites in the country were at 42.88% capacity.
The conflict in the Middle East and the resulting surge in prices have slowed Europe’s efforts to replenish its gas reserves, as Asia emerged as the preferred destination for spot LNG cargoes due to its stronger spot LNG prices during the crisis.

In recent years, Germany has also significantly increased the proportion of LNG imports within its overall gas supply mix. Interestingly, LNG imports have become a more significant component of the total supply, rising to 12% in the first half of 2026, up from 10% in 2025, despite the shock supply loss from the Middle East due to the closed Strait of Hormuz.