The forum took place during Presidential Chief of Staff Kang Hoon-sik’s visit to Canada as a special envoy for strategic economic cooperation, marking his second trip to the country following a visit in late January 2026. Highlighting the significance of enhanced energy cooperation, Seoul’s industry ministry noted that “the energy and resource supply-chain environment is being reshaped by prolonged instability in the Middle East and intensifying competition over critical mineral supply chains.”

The ministry added, “In this context, Korea and Canada, which are geopolitically stable and share common values, are being regarded as each other’s best strategic partners.”

According to the ministry, South Korea will raise imports of Canadian crude oil from 4.88 million barrels in 2025 to as much as 16 million barrels in 2026, representing an increase of about 3.3 times. Authorities are also examining the possibility of increasing annual imports to 20 million barrels.

“In this case, Korea would emerge as Canada’s third-largest destination for crude oil exports after the United States and China,” the ministry said.

It further stated, “The two countries agreed to further strengthen such mutually beneficial cooperation, given that this also presents an opportunity for Canada which has supplied more than 90 percent of its crude oil production to the US to diversify its export routes to Asia, the world’s largest crude oil consumption region (by volume).”

The expansion of energy cooperation comes as South Korea seeks to diversify energy procurement and reduce dependence on routes passing through the Strait of Hormuz.

The LNG sector also featured prominently in the discussions. South Korea aims to secure 3.4 million metric tons of Canadian LNG annually, valued at 6.41 billion Canadian dollars ($4.6 billion), through increased investment in Canadian projects involving natural gas liquefaction plants and export infrastructure. The ministry said those volumes could be achieved if Seoul participates in the second phase of the LNG project in Kitimat, British Columbia, where a final investment decision is expected by the third quarter of this year.

Officials said continued energy cooperation in LNG could increase the share of Canadian LNG in South Korea’s imports from 1.7 percent in 2025 to 3 percent in 2031.

This milestone in ACG field ushers in a new era for an asset that has been a cornerstone of Azerbaijan’s energy sector for nearly three decades. Previously known primarily for its substantial oil output, the ACG field is now diversifying its operations with the introduction of natural gas extraction.

The first gas is being produced from a well drilled from the West Chirag platform. This operation is anticipated to yield critical reservoir and flow data, essential for evaluating the broader gas resource base within ACG and informing future development strategies. Industry estimates place the field’s non-associated gas resources at approximately 4 trillion cubic feet (Tcf) of recoverable reserves, with a potential upside reaching up to 6 Tcf. This underscores the significant untapped potential in the region.

“This is a big day for Azerbaijan and for the ACG co-venturers,” said Gio Cristofoli, Regional President for Azerbaijan, Georgia and Türkiye at bp.

“ACG has a long and successful history and now, nearly three decades into oil production, the field continues to hold potential to deliver value for the nation and its investors as it starts this new chapter,” he added.

The initial well was expertly drilled into two target reservoirs situated beneath the existing oil-producing zones of ACG. This exploration confirmed the presence of gas resources in the Qirmaki Upper Sand reservoir and identified high-pressure gas in the deeper Qirmaki Lower Sand reservoir, which will be the focus of the initial testing and production activities. The produced gas and condensate will be efficiently transported to the Sangachal Terminal by utilizing the existing ACG infrastructure. This integration allows the project to leverage well-established offshore facilities and export systems, minimizing logistical complexities and enhancing operational efficiency. The development of ACG field is a testament to strategic planning and long-term vision.

“The project contributes to Azerbaijan’s plans to increase energy supplies to Europe while supporting the country’s energy transition efforts,” further added Cristofoli.

bp operates the ACG field on behalf of a consortium of partners, including SOCAR, MOL, INPEX, ExxonMobil, TPAO, and ONGC Videsh. The field’s oil production commenced in 1997, establishing it as a vital component of Azerbaijan’s energy sector for decades.

The formalization of this collaboration occurred recently in Muscat with the signing of a Memorandum of Understanding (MoU). The agreement was executed by Montri Rawanchaikul, Chief Executive Officer of PTTEP, and Mahmoud al Hashmi, Chief Executive Officer of OQ Exploration and Production New Ventures LLC (OQEP). This pivotal Oman Thailand energy agreement underscores a commitment to shared growth.

“The MoU covers the exchange of technical expertise, experience and best practices, together with initiatives in human capital development, integrated digital solutions and continuous improvement for upstream operations”, PTTEP said in a statement.

“This collaboration reflects the shared commitment between PTTEP and OQEP to strengthening strategic partnerships and enhancing organisational capabilities for long-term growth in the energy sector”, the Thai company added.

This new agreement aligns with a wider strategic objective by both national energy companies to deepen their relationships with international energy firms and to broaden their upstream footprint. OQEP and PTTEP already maintain a strong presence in Oman through various joint ventures.

Notable existing collaborations include the substantial Block 61 gas concession. In this venture, OQEP holds a 30 per cent stake, while PTTEP has a 20 per cent interest, alongside partners BP and PETRONAS. Furthermore, PTTEP possesses a 2 per cent participating interest in Block 6, which is Oman’s largest onshore oil producing asset, operated by Petroleum Development Oman (PDO). PTTEP Group also holds a 1 per cent participating interest in Block 53, located in southern Oman, which is known for the heavy oil-bearing Mukhaizna field operated by Occidental Petroleum. The ongoing Oman Thailand energy cooperation is built on this foundation.

Beyond upstream activities, PTTEP also has interests in Oman’s midstream sector. The company holds a 2 per cent interest in Oman LNG and an indirect 0.7 per cent interest in Qalhat LNG. Collectively, these facilities have a combined production capacity of 11.4 million tonnes per annum.

The latest MoU with PTTEP is an integral part of OQEP’s broader international partnership strategy, which has been actively pursued in recent years. This Oman Thailand energy collaboration is a testament to that strategy.

According to Türkiye’s Energy and Natural Resources Ministry, the arrangement constitutes a new phase in the established energy partnership between the two nations. The ministry emphasized that this initiative directly supports Ankara’s strategic objective to establish itself as a regional energy hub while simultaneously enhancing the energy security of Türkiye, neighboring countries, and the broader European market.

The Absheron gas-condensate field, positioned approximately 100 kilometers southeast of Baku in the Caspian Sea, stands as one of Azerbaijan’s most substantial offshore gas discoveries. The field contains an estimated 350 billion cubic meters of natural gas reserves coupled with 45 million tons of condensate. These reserves position the Absheron field as a cornerstone of Azerbaijan’s comprehensive strategy to expand gas exports to regional markets and throughout Europe.

The field initiated commercial production during 2023 under its inaugural development phase, spearheaded collaboratively by SOCAR and TotalEnergies. Planned expansion projects are anticipated to substantially elevate production volumes during the coming years, directly supporting the objectives outlined in the natural gas supply agreement signed between Türkiye and Azerbaijan.

Speaking at the opening ceremony of Baku Energy Week,Türkiye’s President Recep Tayyip Erdogan underscored the expanding energy partnership between Türkiye and Azerbaijan. He highlighted multiple landmark infrastructure projects that demonstrate the depth of bilateral cooperation, including the Baku-Tbilisi-Ceyhan oil pipeline, the Baku-Tbilisi-Erzurum gas pipeline, and the Trans-Anatolian Natural Gas Pipeline (TANAP). Erdogan also referenced ongoing collaboration in the Azeri-Chirag-Gunashli and Shah Deniz fields, along with the emerging Shafag-Asiman project, as evidence of strengthening bilateral ties. The President directed particular attention toward future opportunities for expanding cooperation on transporting Turkmen gas through Azerbaijan and Türkiye.

“There are significant opportunities ahead of us to further develop our cooperation on the export of Turkmen gas via Azerbaijan and Türkiye,” Erdogan said.

The Trans-Caspian pipeline concept, a proposal under discussion for an extended period, would facilitate the transport of Turkmen gas across the Caspian Sea to Azerbaijan. From there, gas could be directed to Türkiye and European markets through the Southern Gas Corridor framework. Though the project has not yet advanced to implementation stages, it remains a significant prospect for broadening Caspian gas exports and diversifying European energy supply channels.

Türkiye’s Energy and Natural Resources Minister Alparslan Bayraktar characterized Türkiye and Azerbaijan as exemplifying models for sustained, long-term energy cooperation. He emphasized that this partnership meaningfully contributes to the energy security interests of both nations while strengthening European energy resilience.

Bayraktar noted that the Trans-Anatolian Natural Gas Pipeline maintains substantial unused capacity and stressed the importance of optimizing existing infrastructure utilization. The minister signaled increasing momentum regarding the transportation of Turkmen gas to Türkiye and Europe through Azerbaijan.

Bayraktar further announced that Türkiye is actively pursuing additional supply agreements while concurrently expanding natural gas and electricity interconnections with neighboring countries and European partners.

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.