Strategies for Efficient Production

To achieve this goal, the Ministry has instructed project stakeholders to evaluate all available technical solutions and alternatives that could shorten the current project timeline. The primary objective is to bring the Harmattan gas field onstream as quickly as possible, allowing for the effective utilization of the region’s reserves.

The development plan highlights several critical components:

• Infrastructure integration: The field will be linked to the Hapiya processing facility via a 50-km gas pipeline, according to Pharaonic Petroleum Company Chairman Hossam Zaki.
• Targeted output: Once fully operational, the project aims to produce approximately 200 million cubic feet of natural gas per day, alongside 4,400 barrels of petroleum condensates daily.
• Technical collaboration: ENPPI is serving as the primary contractor, working in close cooperation with Petrojet and Petroleum Marine Services.

Advancing Drilling and Exploration

Beyond the specific development of the Harmattan gas field, the Minister underscored the importance of deploying cutting-edge technology in drilling and exploration. These efforts are designed to improve success rates and maximize the overall yield of Egypt’s energy resources.

The Pharaonic Petroleum Company reported that it successfully met its production targets for the 2025–2026 fiscal year. Looking ahead, the firm is focused on expanding its infrastructure capabilities and reviewing exploration opportunities in the Ras El Bar, North Damietta, and Al-Borg areas.

The Tort-6 well is expected to commence production before the end of the year, with a targeted output of 40 million cubic feet of gas per day.

As part of the ongoing exploration program, drilling is also planned at the West Atoll exploratory well using the Valaris DS-12 rig. The project represents an investment of around $91 million and will target a depth of 6,000 meters. In addition, drilling activities are planned for the Benio well in the Ras El Bar area.

Multi-Billion Dollar Capital Allocation Across Key Sites

The comprehensive Rich Gas Development Project spans critical operational assets within the United Arab Emirates. A significant portion of the capital—$3.9 billion—will fund the construction of a new natural gas processing train at the Habshah facility. Engineering contractor Wison Engineering has been tapped to construct this unit at the Habshah complex, recognized as the largest gas processing establishment in the UAE.

In addition, $4.3 billion will be directed toward a new natural gas liquids fractionation unit located at Ruwais LNG. These targeted allocations reinforce national energy infrastructure while scaling processing throughput across core UAE facilities.

Expanding Export Reach and Operational Capabilities

The Ruwais site is projected to become one of the largest liquefied natural gas complexes in the Middle East region. Scheduled to commence operations in late 2028, the installation will more than double current export capabilities, raising the total LNG capacity to approximately 15 million tons per year. The facility will operate two 4.8-million-tons-per-year liquefaction trains equipped with artificial intelligence and advanced technological systems aimed at optimizing operational safety, efficiency, and emissions management.

This major expansion comes as the business strengthens its gas production capacity to meet favorable long-term demand outlooks, navigating broader regional supply dynamics. Through this ongoing Rich Gas Development Project, the firm aims to optimize natural gas processing performance and strengthen regional energy infrastructure.

Highlighting the milestone, Chief Executive Fatema Al Nuaimi stated: “This is a defining moment for ADNOC Gas. With the final investment decision and contract awards for the Rich Gas Development Project, we are not only accelerating one of the world’s largest gas-processing growth programs – we are raising our ambition, targeting 60% EBITDA growth by 2030.”

Al Nuaimi added that these capital commitments will expand export capabilities, stating, “These strategic investments will significantly expand our natural gas processing and export capacity, unlock lasting value for our shareholders, and position ADNOC Gas at the heart of the UAE’s energy future.”

Addressing inquiries from Senator Mohd Hasbie Muda regarding proposed long-term crude oil, gas, and diesel supply arrangements with Russia alongside offshore field developments in Turkmenistan, the ministry clarified that all commercial decisions are governed by strict international standards. Potential crude oil imports from foreign partners must comply with international trade policies, pricing feasibility, product specifications, logistics, payment methods, transportation, insurance, and prevailing legal regulations.

Strengthening Regional Gas Supply Partnerships

In line with its strategic focus on gas supply enhancement and diversification for energy security, Petroliam Nasional Bhd (Petronas) entered into pivotal agreements on 20th June 2026 with two state-backed energy companies in Turkmenistan. The agreements include a Production Sharing Agreement covering Offshore Blocks 19 and 20, as well as a Cooperation Agreement to conduct a 2D seismic survey across northern offshore blocks. Petronas stated these arrangements reflect a commitment to unlocking subsurface potential, improving technical understanding, and supporting Turkmenistan in regional energy markets.

Strategic Benefits for National Resilience

The ministry said the benefits of broadening the nation’s energy mix could be achieved through three primary focus areas. These include strengthening national energy security by securing reliable long-term energy supplies while improving flexibility in handling fuel pricing and subsidy policies as supply options become more diversified.

According to the ministry, the initiative is also expected to enable Malaysian oil and gas services companies to integrate into global value chains, enhance domestic technical capabilities and support the creation of high-value employment opportunities.

At the same time, the ministry acknowledged that the strategy would not completely shield Malaysia from movements in international energy prices.

“Nevertheless, access to more diverse and competitive energy supply sources has the potential to support supply stability and reduce exposure to volatility in global energy markets,” it said.

“This will place Malaysia in a stronger position to safeguard the interests of the rakyat, industry and the national economy over the long term,” it added.

On behalf of the Tim Hodgson, Canada’s Minister of Energy and Natural Resources, Jill McKnight, Minister of Veterans Affairs and Associate Minister of National Defence, announced a binding agreement between Ksi Lisims LNG and Germany’s Uniper SE. The LNG supply deal represents the first agreement of its kind and provides for Uniper to purchase two million tonnes per annum (mtpa) of Canadian LNG over a period of up to 20 years.

Initial deliveries are expected to commence in 2032. The agreement will serve customers across Uniper’s principal markets, including Germany, the United Kingdom, Sweden and the Netherlands. By securing long-term arrangements with European allies, Canada is broadening its export destinations beyond the United States, providing greater economic stability, job security and increased trade sovereignty.

The LNG supply deal also supports the federal government’s trade diversification agenda, moving from less than 0.01 percent of Canadian natural gas exports reaching non-U.S. markets in 2024 to an estimated 55 percent by the early-to-mid 2030s.

Project Expected to Deliver Economic Growth and Lower-Emission LNG Production

Led by the Nisga’a Nation, Ksi Lisims LNG is a $30-billion development that is expected to become Canada’s second-largest LNG facility. By the early-to-mid 2030s, the project has the potential to account for 13 percent of Canada’s total natural gas exports.

It is also expected to rank among the world’s lowest-emission LNG operations, producing emissions that are 94 percent below the global average. The project was referred to the federal Major Projects Office in November 2025.

The latest LNG supply deal also builds upon the landmark first Canada–Europe LNG letter of interest reached in May 2026, which outlined a potential 20-year agreement between Ksi Lisims LNG and Germany’s SEFE to provide one million tonnes of LNG annually from Canada to Europe. As a result, one quarter of Ksi Lisims LNG production has now been committed to Canada’s European allies.

The agreement represents an important milestone for both the Nisga’a Nation and Ksi Lisims LNG. It is expected to generate significant economic activity, support the creation of thousands of jobs across British Columbia and contribute $15 billion to Canada’s GDP.

Project Overview and Resource Assessment

The Cronos field, located in Block 6, contains more than 3 trillion cubic feet (tcf) of gas initially in place (GIIP). The Cyprus gas production initiative is designed to extract and process these reserves through a coordinated development strategy. Production capacity is anticipated to reach 500 million cubic feet per day (mmcf/d), translating to approximately 2.8 million tons per year (mmt/y) of liquefied natural gas (LNG).

Block 6 operations are managed by Eni, which holds a 50% interest in the project, with TotalEnergies serving as the project partner. The Cronos gas field was initially discovered in 2022, followed by successful appraisal activities completed in 2024.

Development Infrastructure and Production Framework

The field development plan incorporates four subsea wells designed to extract gas from the offshore reservoirs. Rather than constructing new processing infrastructure, the project leverages existing facilities in the region. Produced gas will be transported and processed at the Zohr facilities located in Egypt, consolidated with other regional production, and subsequently transferred to the Damietta LNG plant for liquefaction and export.

Regional Cooperation and Commercial Framework

The Cronos field FID followed commercial agreements finalized in October 2025 between Egypt and Cyprus authorities. Several key agreements support the project structure:

• A Handling, Transportation and Processing Agreement (HTPA) between Eni, TotalEnergies, the Egyptian Natural Gas Holding Company (EGAS), IEOC (Eni’s Egypt subsidiary), and Petrobel
• A tolling contract between Eni, TotalEnergies and Damietta LNG export facility
• A tariff agreement between Block 6 partners and Egypt’s Ministry of Petroleum and Mineral Resources

Reflecting on the Cronos field FID, Karim Badawi, Minister of Petroleum and Mineral Resources, said, “The Cronos project’s final investment decision is not merely a step toward gas field development, but an international endorsement of Egypt’s strategy to leverage infrastructure and transform resources into shared economic value. What we are witnessing today is a practical translation of the state’s vision to make Egypt a major energy hub in the Eastern Mediterranean and a reliable partner in supporting global energy security.”

Eni CEO Claudio Descalzi commented, “Cronos fast-track initiative marks a concrete milestone in positioning Cyprus as a European gas producer and exporter, and it unlocks the establishment of a regional gas hub in the Eastern Mediterranean by leveraging Egypt’s existing hydrocarbon infrastructure. It is furthermore an example of international cooperation and a concrete contribution to the diversification and security of Europe’s gas supply.”

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.

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.

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.

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.