Chevron takes Final Investment Decision on Leviathan gas expansion

Chevron Corporation (NYSE: CVX) by its subsidiary, Chevron Mediterranean Limited (CML), and the working interest owners of the Leviathan natural gas reservoir have reached a Final Investment Decision (FID) to expand the production capacity of the strategic Leviathan production platform located offshore Israel.

“Chevron is a leading energy player in the Eastern Mediterranean where we are focused on natural gas production and exports. Our operations are critical to meeting the growing energy needs of local and regional markets,” said Clay Neff, president of Chevron Upstream.

“Our decision to invest in the expansion of Leviathan’s production capacity reflects our confidence in the future of energy in the region. Pragmatic U.S. and regional energy policies are helping to strengthen energy security across the Eastern Mediterranean and foster an environment that encourages investment in the Middle East and globally.”

The Leviathan expansion project is expected to come online towards the end of this decade.

The project includes drilling three additional offshore wells, adding additional subsea infrastructure, and enhancing the treatment facilities on the Leviathan production platform as we progress towards increasing total gas delivery to Israel and the region to approximately 21 billion cubic meters (BCM) annually from the Leviathan reservoir.

“This milestone demonstrates our ongoing commitment to partner with the State of Israel to develop natural gas resources and provide essential energy to millions of people in Israel, Egypt and Jordan,” said Jack Baker, managing director of Chevron’s Eastern Mediterranean region.

The Leviathan production platform is located approximately 10 kilometers offshore Dor, Israel.

Leviathan working interest owners include Chevron Mediterranean Limited as operator (39.66%), NewMed Energy (45.34%), and Ratio Energies (15%).

In addition to Leviathan, Chevron’s assets in the Eastern Mediterranean include the Tamar gas producing field (offshore Israel), and the Aphrodite gas field which is currently in development (offshore Cyprus). Chevron is also the operator of 2 Egyptian exploration blocks and is in a non-operated joint venture (NOJV) in one Egyptian exploration block (in the Mediterranean Sea).

SOCAR Acquires 10% Stake in Baleine Oil and Gas Field Development Project

SOCAR has signed an agreement with Eni S.p.A. to acquire a 10% participating interest in the development project of the Baleine oil and gas field located offshore Côte d’Ivoire.

The Agreement was signed between SOCAR President Rovshan Najaf and Eni S.p.A. CEO Claudio Descalzi on the sidelines of the World Economic Forum Annual Meeting 2026.

This transaction represents SOCAR’s entry to Africa’s vast oil and gas resources and aligns strategically with SOCAR’s global expansion vision.

The transaction also forms part of a broader strategic collaboration between SOCAR and Eni S.p.A across various segments of the energy industry.

The implementation of this agreement and the closing of the transaction are subject to obtaining the necessary approvals from relevant regulatory authorities, as well as the fulfillment of other customary terms and conditions.

Baleine is considered one of the largest oil and gas discoveries made in West Africa in recent years. The giant offshore oil and gas field was discovered in 2021, with production commencing in 2023.

Baleine field currently produces over 62,000 barrels of oil and more than 75 million cubic feet (approximately 2.1 million cubic meters) of gas per day from Phases 1 and 2 of its development. With the launch of Phase 3, production is expected to rise to 150,000 barrels of oil and 200 million cubic feet (approximately 5.7 million cubic meters) of gas per day.

It is particularly noteworthy that Baleine is Africa’s first net-zero emissions offshore oil and gas project.

Johan Castberg strengthens Norway as a long-term energy exporter

31 March, at 10.35, the Johan Castberg oil field in the Barents Sea came on stream. The field will be producing for 30 years and bolsters Norway’s role as a reliable and long-term supplier of energy.

At peak, Johan Castberg can produce 220,000 barrels of oil per day, and recoverable volumes are estimated at between 450 and 650 million barrels.

"This is a red-letter day.The Johan Castberg field will contribute crucial energy, value creation, ripple effects and jobs for at least 30 years to come. We expect that this major field development with a price tag of NOK 86 billion (2024) will be repaid in less than two years," says Geir Tungesvik, Equinor's executive vice president for Projects, Drilling and Procurement.

12 of the 30 total wells are ready for production, and this is sufficient to bring the field up to expected plateau production in the second quarter of 2025.

"Johan Castberg opens a new region for oil recovery and will create more opportunities in the Barents Sea. We've already made new discoveries in the area and will keep exploring together with our partners. We've identified options to add 250-550 million new recoverable barrels that can be developed and produced over Johan Castberg," says Kjetil Hove, Equinor's executive vice president for Exploration & Production Norway.

The Norwegian supplier industry has accounted for more than 70 per cent of deliveries to the project during the development phase. In operation, this will increase to more than 95 per cent, with a Northern Norwegian share of more than 40 per cent. One of three employees on board the FPSO lives in Northern Norway. 84 per cent of the revenue from the field will be transferred to the Norwegian state through tax and the state's direct participating interest.

The field's supply base and helicopter base are in Hammerfest and will be operated from Equinor's office in Harstad. A total of 30 wells will be drilled on the Johan Castberg field, and drilling operations are expected to continue towards late 2026, which will yield significant activity in Hammerfest.

"Johan Castberg has been a massive and challenging project, and I want to extend my very sincere thanks to everyone who contributed on the road leading to first oil and operation, both our partners Vår Energi and Petoro, our suppliers and our own employees. 79 million hours of work have been recorded in the project, and the HSE results are very good. Now the field will produce for 30 years and generate substantial values," Tungesvik says.

Facts about Johan Castberg

• Licensees: Equinor Energy AS (operator) 46.3%, Vår Energi ASA 30%, Petoro AS 23.7%.
• The Johan Castberg field consists of the Skrugard, Havis and Drivis discoveries, which were made between 2011 and 2014.
• Location: Johan Castberg is located approx. 100 kilometres north of the Snøhvit field in the Barents Sea in blocks 7219/9 and 7220/4,5,7 approximately 150 km from Goliat and around 240 km from Melkøya. The water depth is 360-390 metres, and Skrugard and Havis are 7 km apart.
• Johan Castberg is the second oil field in the Barents Sea and Norway’s northernmost field.
• The field development is based on a production vessel tied back to an extensive subsea field with a total of 30 wells distributed between 10 well templates and two satellite structures.

FPSO Almirante Tamandaré producing and on hire

SBM Offshore announces that FPSO Almirante Tamandaré is formally on hire as of February 16, 2025 after achieving first oil and the completion of a 72-hour continuous production test leading to Final Acceptance.

FPSO Almirante Tamandaré is the largest oil producing unit in Brazil with a processing capacity of 225,000 barrels of oil and 12 million m3 of gas per day. This FPSO has an estimated greenhouse gas (GHG) emission intensity below 10 kgCO2e/boe[1] and benefits from emission reduction technologies such as the closed flare technology which increases gas utilization, preventing it from being burnt into the atmosphere. FPSO Almirante Tamandaré is the first unit in Brazil to receive a Sustainability-1 Notation[2] certification reflecting the Company’s efforts to reduce emissions over the lifecycle of the vessel.

FPSO Almirante Tamandaré is owned and operated by special purpose companies owned by affiliated companies of SBM Offshore (55%) and its partners (45%). The FPSO will operate under a 26.25-year charter and operation services contracts with Petróleo Brasileiro S.A. (Petrobras).

FPSO Almirante Tamandaré is installed at the Búzios unitized field located in the Santos Basin, approximately 180 kilometers offshore Rio de Janeiro in Brazil. The Búzios unitized field is operated by Petrobras (88.99%) in partnership with CNODC (3.67%) and CNOOC (7.34%).

TechnipFMC Awarded Major iEPCI™ Contract for Shell’s Gato do Mato Development Offshore Brazil

TechnipFMC (NYSE: FTI) has been awarded a major(1) integrated Engineering, Procurement, Construction, and Installation (iEPCI™) contract by Shell for its Gato do Mato greenfield development offshore Brazil.

In addition to integrated execution, the project will utilize Subsea 2.0® configure-to-order (CTO) subsea production systems. Combining both offerings will enable streamlined project management through a single interface and accelerate time to first oil.

Jonathan Landes, President, Subsea at TechnipFMC commented: “Throughout our 30-year partnership with Shell, we have built an overwhelmingly strong record of delivery. Our success in integrating and industrializing innovative solutions gives us the utmost confidence in providing the schedule certainty Shell requires for this flagship project offshore Brazil.”

TechnipFMC Awarded Large iEPCI™ Contract for Equinor’s Johan Sverdrup Phase 3 Offshore Norway

TechnipFMC (NYSE: FTI) has been awarded a large integrated Engineering, Procurement, Construction, and Installation contract by Equinor for the Johan Sverdrup Phase 3 development in the Norwegian North Sea.

The Johan Sverdrup field, which originally began production in 2019, is now one of the largest developments in the region. This latest phase will increase production by tying in additional wells to the current infrastructure, which is powered by low-emission resources onshore.

Jonathan Landes, President, Subsea at TechnipFMC commented: “It is a privilege to contribute once again to the development of this field, where we delivered subsea production systems for each of the previous phases. We are excited to leverage our integrated execution model to further enhance this world-class offshore asset.”

This direct award follows an integrated Front End Engineering and Design study. TechnipFMC will design, manufacture, and install subsea production systems, umbilicals, and rigid pipe that will tie new templates into the existing Johan Sverdrup field center.

Shell starts up new facility in UK North Sea, restoring production from the Penguins field

Shell has restarted production at the Penguins field in the UK North Sea with a modern floating, production, storage and offloading (FPSO) facility (Shell 50%, operator; NEO Energy 50%). The previous export route for this field was via the Brent Charlie platform, which ceased production in 2021 and is being decommissioned.

Peak production is estimated at around 45,000 barrels of oil equivalent per day (boe/d) and currently has an estimated discovered recoverable resource volume of approximately 100 million boe. Although primarily oil production, Penguins will also produce enough gas to heat around 700,000 UK homes per year.

The new FPSO will have around 30% lower operational emissions compared with Brent Charlie and is expected to extend the life of this important field by up to 20 years.

“Today, the UK relies on imports to meet much of its demand for oil and gas,” said Zoë Yujnovich, Shell’s Integrated Gas and Upstream Director. “The Penguins field is a source of the secure domestic energy production people need today, and the FPSO is a demonstration of our investment in competitive projects that create more value with less emissions.”

Although oil will be transported by tanker to refineries outside of the UK, these include ones that supply refined products like petrol and diesel back to the UK because of its limited refining capacity.

Natural gas will be transported through the existing pipeline to the St Fergus gas terminal in the north-east of Scotland, which supplies the UK’s national gas network.

The redevelopment of the Penguins field has involved drilling additional wells, which are tied back to the new FPSO. The field is in 165 metres (541 feet) of water depth, around 150 miles north-east of the Shetland Islands. Discovered in 1974, the field previously produced oil and gas between 2003 and 2021.

Notes to editors

• The Penguins FPSO is operated by Shell U.K. Limited, which is a subsidiary of Shell plc. As announced on December 5 2024, Shell U.K. Limited and Equinor UK Ltd are to combine their UK offshore oil and gas assets and expertise to form a new company which will be the UK North Sea’s biggest independent producer. On deal completion, the new independent producer will be jointly owned by Equinor (50%) and Shell (50%). The joint venture will take on Shell’s equity interests in Penguins.
• The Penguins FPSO was built by Sevan – a technology, design and engineering company based in Norway – and is the first new Shell-operated facility in the UK North Sea for over 20 years. It is a compact facility with a cylindrical hull design, providing more efficiency and flexibility. It has a flareless system, which recycles vapour back into the tanks and reduces emissions.
• According to the UK regulator, the North Sea Transition Authority, production of oil and gas has declined by 11% in the last year (Source: NSTA) and UK production is falling faster than demand (Source: DESNZ).
• The estimated peak production and current estimated recoverable resources presented above are 100% total gross figures.
• Current estimated discovered recoverable resource volumes of this development are approximately 100 million boe. The estimate of resource volumes is currently classified as 2P (the sum of proved reserves plus probable reserves) and 2C (the best estimate scenario of contingent resources) under the Society of Petroleum Engineers’ Resource Classification System.
• On Shell’s Capital Market Day in 2023, Shell committed to deliver upstream and integrated gas projects coming on stream between 2023 to 2025 with a total peak production of greater than 500,000 barrels of oil equivalent per day. Penguins is expected to contribute to this commitment.
• Our target is to become a net-zero emissions energy business by 2050. By the end of 2023, we had achieved more than 60% of our target to halve emissions from our operations (Scopes 1 and 2) by 2030, compared with 2016.

ONGC and bp sign contract to enhance production from Mumbai High

Oil and Natural Gas Corporation Limited (ONGC) and bp have signed a contract under which bp will serve as the Technical Services Provider (TSP) for the Mumbai High field, India’s largest and most prolific offshore oil field.

ONGC will retain ownership and operational control of the field. Under the terms of the contract, bp will receive a fixed fee for a period of two years for its deployed personnel, followed by a service fee linked to incremental oil and gas production. bp will work in close collaboration with ONGC to stabilize the field’s current production decline and restore it to a robust growth trajectory.

Leveraging its extensive experience in managing some of the world’s largest oil fields, bp will optimize oil recovery at Mumbai High by conducting comprehensive reviews of sub-surface models, implementing system optimizations, and enhancing reservoir management practices. This partnership is anticipated to significantly boost domestic oil and gas production, thereby increasing revenue for ONGC and benefiting the people of India, while also yielding higher service fee returns for bp.

bp will assemble a team of technical experts to commence work by March 2025. In support of this initiative, both companies have already established a Senior Management Team and a Joint Management Team to ensure seamless project execution.

Honourable Minister of Petroleum and Natural Gas (MoPNG) Shri Hardeep Puri, in whose office the signing took place, said: “India’s quest towards energy self-sufficiency under the dynamic leadership of Hon’ble PM Narendra Modi Ji gets a massive boost as ONGC onboards its energy partner bp as Technical Service Provider for the Mumbai High Field, landmark field which has been providing energy security to us since 1974. While ONGC continues to retain the ownership of the field, this unique technology collaboration with BP’s expertise in managing complex mature reservoirs and implementing advanced recovery technologies and best operational practices will help in enhancing the production from this iconic field.”

Reflecting on the strategic importance of the collaboration, Secretary, Ministry of Petroleum and Natural Gas, Government of India, Shri Pankaj Jain, said: “This strategic engagement represents a critical step in leveraging global best practices and cutting-edge technologies to optimize production at Mumbai High. I am confident that through this collaboration, we will reinforce our commitment to energy self-reliance and sustainable growth, ensuring a brighter future for India’s energy landscape.”

Shri Arun Kumar Singh, Chairman and CEO, ONGC, said “By engaging a TSP, ONGC aims to realize the enhanced potential of the Mumbai High field by leveraging cutting-edge technologies and global best practices, securing its future contribution to India's energy landscape.”

Kartikeya Dube, Head of country and Chairman bp India said, “We are extremely proud and privileged to be selected as a partner by ONGC and look forward to bringing our international experience and technical expertise to the Mumbai High field. This opportunity further underpins our commitment to exploration and the production of oil and gas in India, creating value for both companies and helping support the country’s vision for energy independence and security.”

bp and Iraq reach final agreement for redevelopment in Kirkuk

bp today reached agreement on all contractual terms with the Government of the Republic of Iraq to invest in several giant oil fields in Kirkuk providing for the rehabilitation and redevelopment of the fields, spanning oil, gas, power and water with potential for investment in exploration. The agreement is subject to final governmental ratification.

Execution of the agreement will follow upon endorsement by the Council of Ministers, after which bp will work closely under the guidance of the Government of Iraq in setting up the new operator, which will be an unincorporated organization comprising predominantly personnel from the North Oil Company (NOC) and North Gas Company (NGC), but also with secondees from bp. The new operating organization will take over operations at Kirkuk from NOC. Subsequent to this agreement, bp expects to form a standalone incorporated joint venture to hold its interests in the operator.

The agreement follows a memorandum of understanding between bp and Iraq signed in July 2024 – of which technical terms were agreed in December and the majority of commercial terms agreed in January – together with previous work bp has done on the fields in Kirkuk from 2013 to 2019.

The agreement is for an initial phase and includes oil and gas production of more than three billion barrels of oil equivalent. It includes the Baba and Avanah domes of the Kirkuk oil field and three adjacent fields – Bai Hassan, Jambur and Khabbaz – in Federal Iraq, all of which are currently operated by the NOC.

The wider resource opportunity across the contract and surrounding area is believed to include up to 20 billion barrels of oil equivalent.

bp executive vice president William Lin said: “This agreement builds on our longstanding and strategic relationship with the Government of Iraq and delivers access to a material new resource opportunity, within one of the world’s most prolific hydrocarbon provinces. It will enable us to bring our experience of managing giant fields to realise the potential of this important asset for Iraq, working alongside and in close partnership with NOC and NGC. This opportunity is fully in line with our priority of pursuing new growth opportunities for bp as we strengthen and high-grade our portfolio across the world. We thank the Government of Iraq for the trust and privilege to deepen our cooperation in-country.”

Under the terms of the agreement, bp will work with NOC, NGC and the new operator to stabilize and grow production. Work will include a drilling programme, the rehabilitation of existing wells and facilities, and the construction of new infrastructure, including gas expansion projects.

Under the agreement, bp’s remuneration will be linked to incremental production volumes, price and costs. bp will be able to book a share of production and reserves proportionate to the fees it earns for helping to increase production.

Investment in the project has the potential to bring opportunity and economic growth into the Kirkuk region – creating tangible benefits for the local population, improving supply chain capability alongside job creation.

The project is fully accommodated within bp’s disciplined financial framework and exceeds bp’s investment returns hurdles. bp expects the project to commence in 2025.

bp successfully completes drilling at El Fayoum-5 Gas Well in North Alexandria Offshore Concession

bp has announced the successful completion of drilling operations at the El Fayoum-5 gas discovery well in the North Alexandria Offshore Concession, marking the final well in its four-slot drilling campaign in the West Nile Delta.

Drilled using the Valaris DS-12 rig, El Fayoum-5 was spudded on February 14, 2025, and encountered four prospective Messinian gas reservoirs, with a total sand thickness of 50 meters at a measured depth of approximately 2,900 meters.

Plans are underway to tie back the discovery to bp’s operated West Nile Delta (WND) Gas Development. This marks bp’s second consecutive gas discovery in recent months, following the successful El King-2 well in the North King Mariout Offshore Concession.

William Lin, EVP gas & low carbon, commented: "This reinforces bp’s commitment to Egypt and its growing energy needs. With Raven Infills Phase 2 already contributing to production, we’re now fast-tracking the El King and Fayoum discoveries to tie into our West Nile Delta infrastructure. The delivery of Raven Infills is fully in line with our priority to grow the upstream and high grade our portfolio across the world.”

The WND Gas Development consists of a series of gas condensate fields located offshore Egypt, within the North Alexandria and West Mediterranean Deepwater concessions. The Raven field, the final phase of the WND project, has been in production since early 2021. Its initial phase included the development of eight subsea wells, located up to 65 km offshore, at water depths ranging from 550 to 700 meters. bp, the project operator, holds an 82.75% stake, while Harbour Energy owns the remaining 17.25%.

INEOS Energy start-up of compression for Breagh field

10th Oct 2024

INEOS Energy today announced the start-up of the electric-driven compressor at the Teesside Gas Processing Plant, which will significantly boost gas flows from the INEOS Operated Breagh Gas Field. The new compressor represents a significant investment that will secure domestic gas supplies for UK homes and industry for years to come, helping to stabilise prices. Electric driven compressors have a lower carbon footprint than the gas alternative, which means that Breagh will remain one of the lowest carbon intensity gas fields in the UK.

INEOS Energy CEO David Bucknall said: “We are delighted to see the electric compressor coming on stream at a critical time for UK gas demand. The project taps into precious North Sea gas reserves with a low carbon intensity and is the kind of investment that is crucial to the energy transition and affordable energy security for the UK.”

The Breagh gas field is operated by INEOS Energy. It is located in the Southern North Sea and was awarded development consent in 2011. It consists of a 12-slot minimum facilities wellhead platform with 11 production wells, a 100km wet gas export pipeline to the beach and a further 11km of onshore pipeline to the Teesside Gas Processing Plant - owned by North Sea Midstream Partners (NSMP) - for processing and delivery of gas into the NTS. The field is a normally unattended installation and has one of the lowest carbon intensities of gas fields in the UK.

Subsea7 awarded contract offshore Norway

Subsea7 today announced the award of a contract by Equinor for a front-end engineering and design (FEED) study with EPCI1 option for the Fram Sør development project, offshore Norway.

The study will finalise the technical definition of the proposed subsea development prior to Equinor and its partners making the final investment decision. Work will begin immediately in our offices in Norway and UK.

If the EPCI option is exercised, any resulting subsea structures, umbilicals, risers and flowlines (SURF) installation scope would be a direct, substantial2 award to Subsea7. Offshore installation activities associated with this contract would be scheduled for 2026, 2027 and 2028.

The Fram Sør area is located 10-30 kilometres north of the Equinor-operated Troll C platform, approximately 70 kilometres north-west of Bergen. The development will be connected to the existing Fram and Troll C infrastructure.

Erik Femsteinevik, Vice President for Subsea 7 Norway said: “This award continues our long-standing collaboration with Equinor. The study enables Subsea7 to engage early in the field development process, optimising design solutions and contributing to the final investment decision. We look forward to working closely with Equinor to unlock the value in Fram Sør”.

Shell to grow working interest in the Ursa platform in Gulf of America

Shell Offshore Inc. and Shell Pipeline Company (SPLC), subsidiaries of Shell plc (Shell), have signed an agreement to increase their stake in the Ursa platform in the Gulf of America.

This will increase Shell’s working interest (WI) in its operated Ursa platform, pipeline, and associated fields from 45.3884% to a maximum of 61.35%, following an agreement to acquire 15.96% WI from ConocoPhillips Company (COP).

“This targeted investment is the latest example of how we are unlocking more value from our existing advantaged Upstream assets and infrastructure,” said Zoë Yujnovich, Shell’s Integrated Gas & Upstream Director. “The acquisition expands our ownership in an established long-producing asset that generates robust free cash flow, while also providing more options for growth.”

The Gulf of America production has among the lowest greenhouse gas intensity in the world. Increasing our working interest in Ursa demonstrates our continued focus on providing secure supplies of domestic energy and pursuing the highest margin and most energy-efficient Upstream investments.

This deal is subject to regulatory clearance, preferential rights election and closing conditions. The deal is expected to be completed by end Q2 2025.
Notes to editors

• Shell is the operator of Ursa Tension-Leg Platform (TLP) and currently holds a 45.3884% working interest (WI) ownership in the asset with BP Exploration & Production Inc. (22.6916% WI), ECP GOM III, LLC (15.96%) and ConocoPhillips Company (COP) (15.96% WI).

The transaction also includes:

• COP’s 15.96% membership interest in the Shell-operated Ursa Oil Pipeline Company LLC, which will be held by Shell Pipeline Company.
• COP’s 1% WI in the Europa prospect (also operated by Shell).
• COP’s 3.5% Overriding Royalty Interest (ORRI) in Ursa. This royalty interest was acquired by COP through the Marathon Oil Corporation merger, which was completed in November 2024.
• Reference to an increase in WI to a maximum of 61.35% is subject to preferential rights election by other WI partners.
• The Ursa TLP, which began production in 1999, is located approximately 130 miles (209 kilometres) southeast of New Orleans within the Mars Basin, one of the most prolific hydrocarbon basins in the world.
• The Ursa/Princess field is well established, having produced more than 800 million barrels of oil equivalent total gross over ~25 years, providing Shell with reliable production and growth opportunities.
• Shell US is the leading deep-water operator and one of the largest leaseholders in the Gulf of America (GoA), focused on opportunities close to our existing assets in the most prolific corridors.
• The reference to our GoA production having among the lowest greenhouse gas intensity in the world is a comparison among other members of the International Association of Oil & Gas Producers.

Fluor-Led JV Supports Successful Completion and Startup of Major Project at Tengiz Oil Field in Kazakhstan

Fluor Corporation (NYSE: FLR) is pleased to announce that it successfully led a joint venture that supported the completion and startup of Tengizchevroil’s (TCO) Future Growth Project (FGP) at the Tengiz oil field in Kazakhstan. The Fluor-led joint venture, including partners Worley, Kazakh Institute of Oil and Gas, and KazGiproNefteTrans Engineering Company, has provided a suite of engineering, procurement, construction, operations and maintenance services for TCO since 2011.

“Achieving first oil is a significant accomplishment and we congratulate the TCO team,” said Mike Alexander, President of Fluor’s Energy Solutions business. “Fluor has supported TCO for the past 14 years and has been active in the Republic of Kazakhstan since 1982, working on projects that have helped shape the oil and gas industry.”

As part of the FGP, a new Third-Generation Plan (3GP) was built at the Tengiz oil field, which was discovered in 1979 and ranks as one of the world’s largest and deepest fields. This project milestone marks the beginning of a ramp-up of crude oil production over the coming months. Once all Tengiz facilities are operating at full capacity, TCO’s total annual crude oil production is expected to reach approximately 40 million tons per annum.

As part of its work on the project, significant contributions and commitments to building a sustainable economic future for residents have been made. These include the development of programs for schools and universities to train craft labor and professional engineers, as well as new capabilities for the Republic of Kazakhstan in engineering, high-tech equipment servicing, project management, construction and fabrication.

Tengizchevroil LLP is a Kazakhstani partnership owned by Chevron (50%), KazMunayGas (20%), ExxonMobil (25%) and Lukoil (5%).

Técnicas Reunidas awarded an engineering and management contract for the Vaca Muerta project

VMOS SA, a company part-owned by YPF —the largest company in the Argentine energy sector— has awarded Técnicas Reunidas the contract for the engineering and management services related to the Vaca Muerta project, the large oil field that extends over 30,000 square kilometers in several provinces in central Argentina.

This oil project, which is the largest in the country and has one of the largest non-conventional oil and gas reserves in the world, strengthens YPF’s position in the global energy market, and also boosts Argentina’s economic development by creating jobs and attracting foreign investments.

The work entrusted to the Spanish company includes the engineering, procurement and construction management services, under an EPCm type contract, for a hydrocarbon storage and dispatch terminal to be located in Punta Colorada, on the coast of the province of Río Negro.

The terminal will have a storage capacity of 600,000 m3, a very significant figure from an international scale perspective, and will be divided into five tanks. Its dispatch capacity will be 62,000 m3 per day through two monobuoys that will be able to load very large crude carriers (VLCC)) tankers.

The worth of the contract awarded to Técnicas Reunidas will amount some 440 million dollars, of which more than 70 million will correspond to engineering and project management services. The total investment to be made by YPF and its partners for the full implementation of the terminal will be around 1.8 billion dollars.

The work entrusted to Técnicas Reunidas will be carried out by engineers from the company’s centers in Madrid, Argentina and Chile. Its execution will require around 1 million working hours.

In a previous stage of this project, Técnicas Reunidas was in charge of optimizing the conceptual engineering previously developed by YPF. This work made it possible to reduce the investment figures and the execution periods for the planned infrastructures, with the aim of enabling the Argentinean company to export fuel at reduced capacity as quickly as possible, once local demand had been met.

The award of the new contract extends Técnicas Reunidas’ relationships with this client, as the Spanish company is currently and successfully completing the project to upgrade the Luján de Cuyo refinery that YPF recently awarded it.

The Vaca Muerta contract is in line with the boost that Técnicas Reunidas is currently applying to its involvement in projects in which construction risks are minimized, in line with the SALTA strategic plan presented last May.

Sanha lean gas connection achieves first gas

Cabinda Gulf Oil Company Limited (“CABGOC”), Chevron’s subsidiary in Angola, and Block 0 partners, have successfully achieved first gas on the Sanha Lean Gas Connection (SLGC) project.

"First gas from the Sanha Lean Gas Connection shows CABGOC’s success in maximizing value from existing resources in Block 0 while growing capabilities in Angola" said Billy Lacobie, managing director of Chevron's Southern Africa Strategic Business Unit. “The Sanha Lean Gas Connection project will help supply gas from Block 0's Sanha field to Soyo power plants and Angola Liquefied Natural Gas (ALNG), serving as a gas hub for CABGOC operations. As a long-term partner, Chevron builds upon a legacy of 70 years of operational excellence in Angola and remains dedicated to continuing to provide reliable, affordable, and lower carbon energy to benefit the people of Angola.”

Currently, CABGOC operations export 300 Million Standard Cubic Feet (MMSCF) per day to ALNG through the Congo River Crossing Pipeline (CRX). The first stage of SLGC will deliver an additional 80 MMSCF per day of Sanha gas to the Angola LNG gas plant. The next stage involves commissioning the Booster Compression (BC) module, which will add 220 MMSCF per day, bringing the CRX pipeline to its full capacity of 600 MMSCF per day.

The SLGC is a world-class facility built in Benguela province. It involved the design and construction of a new platform, which was integrated with the existing Sanha facilities and the CRX Pipeline. This integration connects the gas supply from CABGOC operations to the Angola LNG Plant (ALNG).

CABGOC operates and holds a 39.2 percent interest in Block 0, a concession adjacent to the Cabinda coastline, and a 31 percent operated interest in a production-sharing contracts in deepwater Blocks 14, located West of Block 0. With 36.4 percent, CABGOC is also the largest equity shareholder in the Angola LNG (Liquefied Natural Gas) project in Soyo, and shareholder with 31 percent in the New Gas Consortium, operated by Azule Energy.

INEOS Energy to acquire oil and gas assets in US Gulf of Mexico

INEOS Energy has today announced the acquisition of the Gulf of Mexico business held by CNOOC Energy Holdings U.S.A. Inc., a U.S. subsidiary of CNOOC International Limited (“CNOOC”).

The deal increases INEOS Energy’s production globally to over 90 thousand barrels of oil equivalent per day. These assets in the Gulf of Mexico are the third major investment by INEOS Energy in the USA, in the past three years, following the 1.4 mtpa LNG deal completed with Sempra in December 2022 and the acquisition of Chesapeake Energy’s oil and gas assets in South Texas in May 2023.

The deal includes a portfolio of non operated assets built around two deep water early production assets (Appomattox and Stampede) in the Gulf of Mexico. In addition, INEOS acquires several mature assets and supporting business.

Brian Gilvary Chairman of INEOS Energy said: “This is a major step for us into the deepwater Gulf of Mexico, which builds on our growing energy business. INEOS Energy is all about competing in the energy transition to provide reliable, affordable energy to meet world demand as the population continues to grow. And progressing carbon storage projects.”

The CNOOC Gulf of Mexico assets and strategic partnerships in major U.S. energy projects, will further complement INEOS’ existing onshore portfolio.

David Bucknall CEO INEOS Energy said, "The USA is a very attractive place for INEOS Energy to invest. This is our third deal in three years following the 1.4 mtpa LNG deal with Sempra and the acquisition of Chesapeake Energy’s oil and gas assets in South Texas. Total capital spend on energy assets in the USA now exceeds $3billion, providing a strong platform for future growth.”

INEOS Energy is committed to a dual track approach, to meet society's energy needs through the current energy transition and to investment in carbon storage. The business is actively producing and trading oil, gas, power and carbon credits, as well as investing in LNG, and Carbon Capture and Storage.

In a world first, INEOS demonstrated the feasibility of CO2 storage on the 8th March 2023. The company captured CO2 from INEOS Oxide in Belgium; transported this cross-border then safely and permanently stored it in the INEOS-operated Nini field in the Danish North Sea. On the 10th September this year world-leading provider of risk, verification and standardization services, DNV, verified that the stored CO2 remains safely and permanently sealed in the Nini West reservoir 1,800 metres below the North Sea seabed. Their verification moves the project closer towards commercialisation, expected next year.

Last week, (10th December) INEOS, the day-to-day operator, with its partners Harbour Energy and Nordsøfonden, announced it had made a Final Investment Decision (FID) on the first commercial phase ‘Greensand Future’ with storage operations set to begin at the end of 2025/early 2026. This decision paves the way for expected investments of more than $150 million across the Greensand CCS value chain.

The acquisition of the Gulf of Mexico business held by CNOOC Energy Holdings U.S.A. is subject to the receipt of regulatory approvals and satisfaction of other customary closing conditions.

Eni kicks off Baleine Phase 2, increasing production in the offshore of Côte d'Ivoire

Today, Eni successfully started production of Phase 2 from the Baleine field, marking a crucial step in the development of the Côte d'Ivoire’s offshore. Thanks to this milestone, production will reach 60,000 barrels of oil per day and 70 million cubic feet of associated gas (equivalent to 2 million cubic metres).

Phase 2 will see the Floating Production, Storage and Offloading Unit (FPSO) Petrojarl Kong deployed alongside the Floating Storage and Offloading Unit (FSO) Yamoussoukro for the export of oil, while 100% of the processed gas will supply the local energy demand through the connection with the pipeline built during the project’s Phase 1. This achievement further consolidates Côte d'Ivoire's role as a producing country on the global energy scenario, strengthening access to energy on a national scale.

The rapid development of Baleine Phase 2 confirms Eni's excellent time-to-market, enhanced also by the renovation and reuse of the 2 units.

The Final Investment Decision for the project was taken in December 2022; Phase 1 was started in August 2023; in parallel, activities for Phase 2 had been carried and completed in full safety.

Baleine is the first net zero emission Upstream project (Scope 1 and 2) in Africa, made possible through the adoption of advanced technologies, which minimize the operations’ carbon footprint, and innovative initiatives developed in close collaboration with the Ivorian ministries. These include the improved cookstoves’ distribution program (i.g. clean cooking program), which leverages the local production and has already benefited over 575,000 people in vulnerable conditions, and the initiative to protect and restore 14 classified forests, both contributing to the project’s carbon neutrality. In addition, a wide range of initiatives in the areas of vocational training, education, health and economic diversification enrich Eni's collaboration with the country.

Eni has been present in Côte d'Ivoire since 2015 with a current equity production of around 22,000 barrels of oil equivalent per day. The company operates 10 blocks in the Ivorian deepwaters (CI-101, CI-205, CI-401, CI-501, CI-801, CI-802, CI-504, CI-526, CI-706 and CI-708) in partnership with Petroci Holding.

With the start-up of Baleine's Phase 2 and the development of Phase 3, currently under study, total production is set to reach 150,000 barrels of oil per day and 200 million cubic feet of associated gas, further consolidating Côte d'Ivoire's role as a regional energy hub and strengthening strategic collaboration with the local partner.

TechnipFMC Awarded Substantial Subsea Contract for Shell’s Bonga North Development in Nigeria

TechnipFMC (NYSE: FTI) has been awarded a substantial contract by Shell Nigeria Exploration and Production Company Limited to supply Subsea 2.0® production systems for the Bonga North development in Nigeria.

The contract covers the design and manufacture of subsea tree systems, manifolds, jumpers, controls, and services.

Jonathan Landes, President, Subsea at TechnipFMC, commented: “Shell was the first to adopt our Subsea 2.0® configure-to-order solution, and continues to deploy it across multiple basins—underscoring its commitment to the technology globally. This award further positions us for future deepwater opportunities in the region.”

Shell invests in Bonga North deep-water project, Nigeria

Shell Nigeria Exploration and Production Company Limited (SNEPCo), a subsidiary of Shell plc, has announced a final investment decision (FID) on Bonga North, a deep-water project off the coast of Nigeria.

Bonga North will be a subsea tie-back to the Shell-operated Bonga Floating Production Storage and Offloading (FPSO) facility which Shell operates with a 55% interest.

The Bonga North project involves drilling, completing, and starting up 16 wells (8 production and 8 water injection wells), modifications to the existing Bonga Main FPSO and the installation of new subsea hardware tied back to the FPSO.

The project will sustain oil and gas production at the Bonga facility. Bonga North currently has an estimated recoverable resource volume of more than 300 million barrels of oil equivalent (boe) and will reach a peak production of 110,000 barrels of oil a day, with first oil anticipated by the end of the decade.

“This is another significant investment, which will help us to maintain stable liquids production from our advantaged Upstream portfolio,” said Zoë Yujnovich, Shell’s Integrated Gas and Upstream Director.

Bonga North will help ensure Shell’s leading Integrated Gas and Upstream business continues to drive cash generation into the next decade.

Notes to editors:

• SNEPCo (55%) operates the Bonga field in partnership with Esso Exploration and Production Nigeria Ltd. (20%), Nigerian Agip Exploration Ltd. (12.5%), and TotalEnergies Exploration and Production Nigeria Ltd. (12.5%), on behalf of the Nigerian National Petroleum Company Limited (NNPC).
• Bonga is a deep-water development located in OML 118, at water depths exceeding 1,000 meters. Production at the Bonga FPSO began in 2005, with a capacity to produce 225,000 barrels of oil per day. The project produced its one-billionth barrel of crude oil in 2023.
• The Bonga North development holds estimated recoverable resource volumes of more than 300 million barrels of oil equivalent (boe). These volumes are currently classified as 2P (proven and probable) under the Society of Petroleum Engineers’ Petroleum Resources Management System.
• The estimated peak production and recoverable resources mentioned above are 100% total gross figures.
• The investment in Bonga North is expected to generate an internal rate of return (IRR) in excess of the hurdle rate for Shell’s Upstream business.
• Shell’s Upstream business continues to set new benchmarks in performance through near-field opportunities like Bonga North, leveraging technical expertise, strong partnerships, and a model built on simplification and replication.