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.

Although Norway is not a member of the EU, it remains the largest supplier of gas to European markets. In recent months, the country has intensified its efforts to persuade the bloc to abandon its opposition to Arctic drilling. Norway has pointed to the Iran war and what they describe as the biggest oil and gas supply disruption in history as reasons why Europe should strengthen access to reliable energy supplies from regions outside conflict zones. The issue was also discussed in Brussels, where Birol met with Norwegian Finance Minister, Jens Stoltenberg, and subsequently called for a reassessment of the moratorium.

Officials Present Contrasting Views on Arctic Policy

“I support the Commission to give a very close look at this issue because it is extremely important for the European energy security,” Birol said.

“The world needs every drop of oil from Norway,” he added.

In a post on X, Birol wrote that during his discussions with the Norwegian official, “I emphasised Norway’s importance for European energy security as countries reassess their energy strategies.”

Norwegian authorities have consistently argued that the line used to define the Arctic should not automatically serve as the boundary for oil and gas exploration.

Addressing the issue this week, Stoltenberg said, “Of course there are environmental concerns that we have to take into account.”

“But to say no, there should be no oil and gas exploration in the Arctic doesn’t make sense for Norway,” he added.

“The Gjøa Subsea Projects demonstrate how we continue to develop our core hubs through efficient tie-back developments, leveraging existing infrastructure and exploration success to create long term value. The project strengthens Gjøa as a long-term production hub and supports our target to produce more than 400 thousand barrels of oil equivalent per day long-term,” said Torger Rød, COO of Vår Energi.

Project Timeline and Resource Estimates

The development is expected to unlock approximately 76 million barrels of oil equivalent in gross proved plus probable reserves. The economic profile of the project remains robust, featuring a breakeven price of less than 35 USD per barrel of oil equivalent and a rate of return exceeding 25%.

Production is scheduled to begin in stages, with the Cerisa field expected to come online during the third quarter of 2027. This will be followed by the start-up of the Gjøa Nord and Ofelia fields in the second half of 2028. This phased subsea development is intended to extend the economic viability of the Gjøa area from the early 2030s to approximately 2040.

Strategic Infrastructure and Regional Impact

By increasing the total throughput of the Gjøa asset, the project is anticipated to lower unit production costs and enhance the overall economics of existing fields in the vicinity. Vår Energi has recently bolstered its position in this region through the acquisition of assets from Pandion and a swap agreement with DNO, which increased its ownership across several producing assets and development projects.

Execution and Partnership Framework

The execution of these offshore projects will follow a “project factory” model. This approach emphasizes standardized technical solutions and coordinated drilling campaigns to accelerate the development timeline. By leveraging established supplier collaborations and execution, the company aims to realize significant synergies during the coordinated drilling and installation phase.

Vår Energi serves as the operator for the Gjøa Subsea projects, holding a 40% interest in Ofelia and a 30% interest in both Gjøa Nord and Cerisa. The partnership for these North Sea oil and gas developments includes several key stakeholders:

• Ofelia: Pandion (20%), Harbour (20%), Aker BP (10%), and DNO Norge AS (10%).
• Gjøa Nord: Petoro (30%), Harbour (28%), and OKEA (12%).
• Cerisa: INPEX (30%), Orlen (30%), and DNO Norge AS (10%).

Equinor and its partners have reached agreement on the development concept for Ringvei Vest, a significant subsea development project that will be connected to the Troll B platform in the Norwegian North Sea. The decision represents a major step forward in advancing the project and defines a common development solution covering seven discoveries and one prospect. With the concept now selected, the groundwork has been established for a potential joint field development. According to Equinor, Ringvei Vest is expected to contribute substantial resources to future production.

Project Scope and Resource Assessment

The discoveries included within Ringvei Vest are Grosbeak, Swisher, Mulder, Kveikje, Toppand, Røver Sør, and Røver Nord, while the prospect Grønngylt is also part of the planned development. These resources are distributed across eight licences involving a total of seven owners. Acting as operator across all licences, Equinor has taken responsibility as the area architect and worked with partners to assess multiple development alternatives. This process involved evaluating which discoveries should be incorporated into the project as well as determining the most suitable host platform. As a result of that work, Ringvei Vest has emerged as one of the largest projects currently in the early development phase on the Norwegian Continental Shelf.

“We estimate that Ringvei Vest will contribute 240 million barrels of oil equivalent. A solid effort has been put in over a long period, and I am confident that together with partners and authorities, we have arrived at the best development solution, which also ensures optimal resource utilisation,” said Kjetil Hove, executive vice president for exploration and production Norway in Equinor.

Strategic Context and Continental Shelf Development

Highlighting the broader industry context, Hove stated, “The Norwegian Continental Shelf is maturing, new discoveries are smaller and costs are increasing. To maintain a high activity level and reliable energy supplies to Europe, it is important to develop marginal discoveries near existing infrastructure and collaborate across licenses. Equinor aims to increase our equity production from the Norwegian Continental Shelf to 1.3 million barrels per day in 2035.”

Operational Infrastructure and Execution Strategy

The planned Ringvei Vest development spans a wide geographical area. Current plans call for the drilling of 13 wells through six subsea templates. Production streams from the wells will undergo separation on the seabed before being transported to the Troll B platform. In addition to serving as the receiving facility, Troll B will provide power to the subsea installations associated with Ringvei Vest. Operational control of the wells is also planned to be handled from Troll B. Once processed, oil from the project will be transported to Mongstad, while gas will be sent to Kollsnes.

Further enhancements linked to Ringvei Vest include the installation of a new compressor on Troll B to expand the platform’s processing capacity. The platform already receives partial power from shore, a feature that supports lower-emission production. This arrangement will allow oil and gas from Ringvei Vest to be produced with reduced emissions while making use of existing infrastructure in the Norwegian North Sea. The agreed concept therefore establishes a framework for resource development, infrastructure utilization and future production growth tied to the Troll B platform.

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 parties will seek alignment on key areas of joint interest on the NCS, with the aim of speeding up the development of resources to uphold high production levels and unlock value.

As a first step the parties have agreed on a set of transactions in the Troll-Fram (Ringvei Vest), Yggdrasil and Wisting areas that will strengthen alignment on future developments.

”Equinor and Aker BP have identified key areas to increase value creation from discoveries that have not yet been developed for production on the Norwegian continental shelf. We have completed important transactions that will contribute to efficient resource utilisation and greater value creation. By aligning interests across these assets, we can enable better and faster project decisions,” says Kjetil Hove, Executive Vice President for Exploration & Production Norway.

The transaction includes the divestment of a 19% interest in several discoveries in the Ringvei Vest area to Aker BP: The Grosbeak, Røver Nord & Sør, Toppand and Swisher discoveries.

The agreement strengthens the alignment of ownership interests in the licenses, supporting a more coordinated approach to development planning and project execution. The parties also aim to include the Kveikje discovery into the Ringvei Vest development.

Equinor is the operator of Ringvei Vest, expected to be a cluster development of multiple oil and gas discoveries in the Troll-Fram area of the North Sea.

In addition, Equinor will divest a 38.16% interest in the Frigg UK licence to Aker BP, enabling a joint development of the Omega Alfa discovery and the Frigg Field oil resource potential in the area. The divestment will enable coordinated appraisal and development of the cross-border discovery.

As part of the transactions, Equinor will increase its ownership in the Wisting discovery from 35% to 42.5% and further strengthen its position in the largest undeveloped discovery on the NCS.

Finally, Aker BP will pay a cash consideration to Equinor of USD 23 million.

“These agreements will enable better development solutions, reduce complexity, and support value creation in line with our long-term strategy,” says Kjetil Hove.

The transactions support Equinor’s strategy to optimise its oil and gas portfolio and enable high-value, timely developments on the Norwegian continental shelf towards 2035.

The agreements have an effective date of 1 January 2026. The transactions are subject to regulatory approvals.

The development of the Symra field includes four wells connected through a subsea template, forming a key component of the infrastructure expansion in the region. To support this integration, Aker BP has implemented modifications on both the Ivar Aasen and Edvard Grieg platforms. These upgrades were necessary to enable the tie-in of subsea infrastructure and to enhance processing capacity at Edvard Grieg. Notably, Symra marks the sixth Aker BP-operated project sanctioned in 2022 to reach production.

“Symra demonstrates what’s possible when strong partners work together: safe delivery, high quality, and faster execution,” said Karl Johnny Hersvik, CEO of Aker BP. Additionally, it creates value for partners, shareholders, and society by entering a new region of the Eiga region and a new type of reservoir on the Norwegian shelf.

Execution of the project has involved close coordination with multiple suppliers. TechnipFMC was responsible for delivering the subsea systems, while Moreld Apply carried out modifications on the Edvard Grieg platform. Aibel, in turn, handled the required upgrades on the Ivar Aasen platform. Drilling operations for the Symra field were conducted by Odfjell Drilling and Halliburton as part of the Norwegian operator’s drilling and wells alliance, contributing to the project’s safe and efficient delivery.

In parallel, Aker BP continues to advance other developments, including the Utsira High project, which comprises two subsea tie-in initiatives and incorporates Solveig in the central North Sea. Solveig Phase 2 has been designed for connection to the Edvard Grieg platform. Aker BP operates the Symra field (PL167/167B/167C) alongside partners Equinor (30%) and DNO Norge (20%).

The 7220/7-5 well is located roughly 16 kilometers southwest of the discovery well 7220/8-1 within the Johan Castberg field and about 210 kilometers northwest of Hammerfest. Drilled by the COSL Prospector rig, the 7220/7-5 well targeted petroleum resources within Lower Jurassic reservoir rocks in the Tubåen Formation. During operations, the well encountered a 26-meter gas column and a 26-meter oil column, with total reservoir rock thickness reaching 39 meters and exhibiting good to very good quality. The overall thickness of the Tubåen Formation was measured at 125 meters. The gas/oil contact was identified at 972 meters below sea level, while the oil/water contact was found at 998 meters. Although formation testing was not carried out, extensive data acquisition and sampling were completed to evaluate the Arctic Norway oil discovery.

Drilling reached a vertical depth of 1,119 meters below sea level before terminating in the Fruholmen Formation from the Upper Triassic, with water depth at the site recorded at 361 meters. The well will now be permanently plugged and abandoned. Preliminary estimates suggest recoverable volumes ranging between 14 and 24 million barrels of oil equivalent. The Norwegian Offshore Directorate indicated that this corresponds to approximately 2.3 to 3.8 million standard cubic meters of recoverable oil equivalent. License partners, including Equinor as operator alongside Vår Energi and Petoro, are evaluating whether the discovery can be connected to the Johan Castberg field, making it part of a broader development strategy on the Norwegian Continental Shelf.

This marks the 17th exploration well in production licence 532, which was awarded during the 20th licensing round on the NCS in 2009. The Johan Castberg field was initially estimated to contain 500–700 million barrels, with ambitions to increase this by an additional 200–500 million barrels. In June 2025, another find, Drivis Tubåen, was recorded in the same area, with estimated volumes of 13–20 million barrels. Equinor also recently initiated construction work for the Isflak development, the first discovery planned to be tied into Johan Castberg, with Aker Solutions in Sandnessjøen building a well frame for two additional wells. The latest Arctic Norway oil discovery follows closely on the heels of another find in the Norwegian sector of the North Sea, drilled using a semi-submersible rig from Odfjell Drilling.

Aker BP, the oil field operator, has described the find as “significant”, saying it might yield 134 million barrels of oil. 

Aker BP CEO, Karl Johnny Hersvik said it was among the “largest commercial discoveries” in Norway in the past 10 years. 

Additionally, Karl Johnny Hersvik said, “Building on the momentum from the oil discovery at East Frigg in 2023, it marks a major step toward our ambition of producing more than one billion barrels from the Yggdrasil area.

“This is the result of a strong collaborative effort between our own teams and our alliance partners and a testament to how new exploration methods push the boundaries.

“We look forward to unlocking even more of the potential in this prolific area.”

The North Sea oil discovery was made in the Yggdrasil area in the Norwegian area, which is not so far from the border with British waters.

It is estimated that by 2030, around 180 of Britain’s more than 280 oil and gas fields in the North Sea will have halted production.

While Norway marks this North Sea oil discovery success, a different approach is being taken by Britain.

Windfall taxes put in place by the Tories and increased by Labour mean UK oil and gas extraction profits stands at 78 per cent.

However, the Government announced plans earlier this year to end the windfall tax. It was introduced in 2022 to help fund support for households struggling with rocketing energy bills in 2030.

Meanwhile, Mr Miliband banned the issue of new licences to explore new oil fields last year. The Government has continued to stand by this pledge, which aligns with the science of what is required to limit dangerous global warming.

Johan Castberg and Havis oil fields are located at a distance of about seven kilometres from each other and will be jointly developed as part of the Johan Castberg Field Development project. The partners involved in the development of production licence PL532 are Statoil (50%), ENI (30%) and Petoro (20%).

The two oil fields are located at water depths of about 360m to 390m and are expected to start delivering oil by 2018, with current recoverable reserves estimated at being 400 to 600 million barrels of oil. The production capacity of the fields is estimated at 200,000 barrels of oil equivalent each day. The plan for development and operation (PDO) of the project is expected to be submitted by 2014.

Discovery and drilling of Johan Castberg and Havis

“The partners involved in the development of production licence PL532 are Statoil (50%), ENI (30%) and Petoro (20%).”

Johan Castberg was discovered in April 2011 and Havis in January 2012. The fields are situated in blocks 7219/9 and 7220/4,5,7. The fields were discovered after the 20th licensing round on the Norwegian Continental Shelf was announced in April 2009 by the Ministry of Petroleum and Energy.

Drilling of Johan Castberg was concluded in early 2011 with the completion of drilling the well (7220/8-1) using Transocean’s rig Polar Pioneer, which encountered hydrocarbons at approximately 1,250m depth below sea level.

Drilling of the Havis prospect concluded in early 2012. The last well, 7220/7-1 was drilled using Aker Solution’s rig, Aker Barents. The well was drilled to a depth of 2,200m below sea level and at sea depth of 365m. Estimated volumes from Havis are expected to be between 200 and 300 million barrels of recoverable oil equivalent.

The appraisal of the Skrugard (now known as Johan Castberg) discovery was concluded in March 2012. Appraisal well 7220/5-1 was drilled using the Transocean Barents drilling rig to a depth of 1,740m below sea level, at a water depth of 388m. The appraisal confirmed the estimated initial volume from the Skrugard and Havis facilities in the range of 400 to 600 million barrels of recoverable oil.

Statoil is also drilling exploration wells around the Johan Castberg area to further increase the resources to make the project more robust.

Development of the Norwegian oil fields

The development concept for the two oil fields was announced in February 2013. The plan includes installation of a floating production unit (FPU/FPSO) with a pipeline to shore and an onshore oil terminal at Veidnes, outside Honningsvag, in Finnmark.

“Johan Castberg and Havis oil fields are located at a distance of about seven kilometres from each other.”

The two fields will share common infrastructure. Production from the fields will be tied in to a semi-submersible floating installation through a subsea production system located in about 380m of water.

A total of 14 production wells are expected to be drilled, in addition to injection wells for water and gas for pressure support.

Transportation of the produced oil from offshore to the onshore oil storage facility will be facilitated by a pipeline measuring 280km in length.

The oil will be stored in two mountain caverns. It will be transferred to the quay through a pipeline. Crude tankers will further transport the oil from the terminal.

Contractors for the Johan Castberg Field Development project

Sevan Marine was awarded with a contract in March 2012 to carry out a concept study for application of an FPSO for the development of the field. The company was also involved in the feasibility study that was conducted for the project earlier in 2011. The contract to carry out the preliminary studies for the development of the two oil fields was awarded to Aker Solutions.