Algeria already stands as Spain’s primary supplier of natural gas through the Medgaz pipeline, a key offshore connection linking the two nations across the Mediterranean. Both sides are now working toward operating the pipeline at full capacity, a step that would translate into roughly a 10% increase in flows and further bolster gas imports. Albares held discussions in Algiers with Algerian President Abdelmadjid Tebboune, along with the country’s foreign and energy ministers. The meetings came just a day after Italian Prime Minister Giorgia Meloni visited the Algerian capital with a similar objective of securing additional supplies. Highlighting Algeria’s role, Albares said, “Algeria is a reliable and consistent supplier at a time when the entire global energy market is unfortunately undergoing a profound transformation” due to the war in Iran.

Commercial terms, including pricing and contract duration, remain subject to negotiations between companies involved. Sonatrach, Algeria’s state-owned energy firm, controls a 51% stake in the Medgaz pipeline, while the remaining share is held by a joint venture between Spain’s Naturgy and the US investment firm BlackRock Inc. Spanning 210 kilometers (130 miles) offshore, the infrastructure was the first pipeline constructed between Algeria and Europe and remains central to Spain’s gas imports strategy.

Relations between the two countries had faced strain in 2022, when Algeria pushed for steep price increases during extended contract talks. The tension coincided with Spain’s closer alignment with Morocco over Western Sahara, a long-standing regional dispute. However, recent developments suggest a reset in ties. In a statement, Tebboune described the outlook for bilateral cooperation as “promising” and characterized it by “notable dynamism.” He also confirmed that Algeria has moved to reactivate the previously suspended friendship treaty with Spain, signaling improved diplomatic and energy cooperation going forward.

Oil ministers across the V8 grouping, which comprises countries like Russia, Saudi Arabia, Iraq, the United Arab Emirates, Kazakhstan, Kuwait, Algeria, and Oman, have decided to increase their production by 137,000 barrels a day (bpd) from October 2025, they remarked in a statement.

It is well to be noted that these countries had already gone on to increase the production by 2.2 million bpd in recent months.

In the statement which was issued after an online meeting that took place on September 07, 2025, these nations said that the new incoming cycle could as well witness an extra 1.65 million bpd, which would eventually come to the market.

According to one of the analysts at Rystad Energy, Jorge Leon, OPEC+ has already caught the market off guard rather than pausing, and the group has pretty evidently signalled ambition with a production surge. Although the barrels may be small, however, the fact is that the message is big.

With OPEC+ to boost oil output in October it is indeed prioritizing market share even if it has to face the risks pertaining to softer prices. Oil prices at present are hovering around $65-70 for every barrel. They have witnessed a dip of 12% in 2025 already as global producers outside of the OPEC+ ramp up their supply and the tariffs go on to curb demand.

It is well to be noted that OPEC+, which happens to comprise the 12-nation Organization of the Petroleum Exporting Countries (OPEC) and its allies, in recent years had gone through many output deductions that have amounted to almost six million bpd.

Analysts, only till a week ago, were saying the V8 was most likely to maintain their present output levels in October 2025. However, by raising the output, even by a comparatively modest 137,000 bpd, the V8 has rather indicated that with OPEC+ to boost oil output in October, they would be willing to weather the prices falling down below $60 a barrel if it means regaining the market share.

According to Leon, in reality, the actual production output is going to be far smaller, given the capacity limits as well as the compensation mechanism that is present. However, it is the perception that often matters and not the physical barrels.

However, he still said that the move raises certain questions pertaining to unity, as countries like Russia happen to depend on high prices so as to fund their war machine, while there are others who are willing to test the lower prices when it comes to the market share.

Geopolitical Perspectives

The real test of OPEC+ is going to be the last three months of 2025, a period in which the seasonal demand tends to be much lower.

Oil specialists happen to be keeping a close eye on the war in Ukraine along with other developments pertaining to US-Russia relations – these are some of the geopolitical factors that could affect the oil prices to a great extent.

Donald Trump, the US president, whose efforts to mediate between Russia and Ukraine have failed to produce the breakthrough he was hoping for, has recently targeted Russian oil and those who are buying it.

In August 2025, Trump imposed higher tariffs on India as a kind of punishment for its Russian oil purchases.

In a meeting which took place with the allies of Ukraine who had gathered in Paris recently, Trump had told the leaders through a video conference that he was pretty much frustrated with the Russian oil purchases by the EU, especially by Hungary and Slovakia.

The fact is that curbing the Russian exports could also free up the market space for the countries in OPEC+.

In Amenas Gas project comprises of the exploitation of four gas fields, namely Tiguentourine, Hassi Farida, Hassi Ouan Taredert and Hassi Ouan Abecheu in the Illizi Basin of the In Amenas region. The In Amenas fields cover an area of more than 2,750km². The initial natural gas reserves in these fields were estimated at 85 billion m³.

Development history of the Algerian gas project

Sonatrach signed a contract with US-based Amoco Corporation in 1998 to jointly develop the four In Amenas gas fields. BP took over Amoco Corporation in the same year and concluded a production-sharing contract (PSC) with Sonatrach for the In Amenas licence. In June 2003, BP entered into a farm-out agreement with Statoil, which bought 50% of BP’s interest in the In Amenas fields.

“BP and Statoil’s working interests in the project are 46% and 45.9% respectively.”

The $1.2bn first phase of the In Amenas Gas project focused on the development of the Tiguentourine gas field. ENAFOR, a subsidiary of Sonatas, was awarded a contract in 2002 to drill 12 development wells on the field.

The engineering, procurement and construction (EPC) contract worth $745m for the production and processing facilities of In Amenas was awarded in the same year to a joint venture between Japanese Gas Corporation and Kellogg, Brown and Root, a subsidiary of Halliburton.

GE Oil & Gas supplied the gas turbines and auxiliary equipments for the In Amenas gas processing plant under a $70m contract awarded in 2003. The In Amenas facility was brought on stream in June 2006.

The gas produced at In Amenas is marketed by Sonatrach. BP and Statoil are reimbursed with the condensate and liquefied petroleum gas output of the facility.

Gas production infrastructure at In Amenas

The gas gathering system at In Amenas comprises of ten inch flow lines connected to manifold station with each manifold tied to four to six wells.

“The $1.2bn first phase of the In Amenas Gas project focused on the development of the Tiguentourine gas field.”

A total of 100km of intra-field pipelines (ranging from ten inch to 24 inch in diameter) were constructed at the In Amenas facility by LEAD, a company based in Syria.

The In Amenas gas treatment plant has a capacity to process 30 million m³ of gas a day. The plant consists of three parallel trains for gas processing and condensate stabilisation. The treatment plant is equipped with CO2 removal, mercury removal, molecular sieve dehydration, LPG recovery, residue gas re-compression and power generation facilities.

The production facility is connected to the Sonatrach distribution system at Ohanet through three 90km long export pipelines. The diameter of the pipeline carrying dry gas is 36in and the pipes carrying condensate and LPG have a diameter of 12 inch.

In Amenas gas project expansion plan

A $213m contract was awarded to Japanese Gas Corporation in May 2011, to deliver a compression project at In Amenas by 2013. The compression project includes the construction of two train inlet compressions to the existing processing plant, new slug catcher facility, a permanent accommodation camp and utility buildings.

The expansion project aims at improving the recovery of wet gas at In Amenas that will help maintain its production capacity of 30 million m³ per day for next 12 years.

Petrofac was awarded a three year contract for multidiscipline consultancy, design and procurement services in January 2013, as part of the development programme to further boost up the hydrocarbon production at In Amenas.

In Amenas siege / terror attack

The In Amenas gas facility was attacked by Islamist terrorists on 16 January 2013. The workers at the facility, including 48 foreign nationals, were taken hostage by the militants as part of the attack. The gas facility was put under seize by the Algerian security forces for four days. In the process, 40 hostages, including five Statoil employees and four BP employees, were killed.

The processing facility was also partly damaged during the fight between the security forces and the terrorists.

The In Amenas gas facility was shut after the attack. BP and Statoil have withdrawn their employees from the facility until the security situation is thoroughly reviewed.

Sonatrach started limited production from the facility in February 2013, by restarting just one production train on behalf of the joint venture partners. The other two production trains of the facility were damaged during the terror attack.

In the meantime, the expansion projects planned for the In Amenas gas facility have been kept on hold until strict security measures are established by the Algerian state. Any new production from the facility is unlikely until 2014.

One such project is the Arzew LNG train or GL3-Z project, which will soon be under construction in Algeria near the city of Arzew, situated about 400km (249 miles) west of Algiers. The country has proven natural gas reserves of 4.5 trillion cubic metres, which amounts to about 2.6% of the world total, and is the world’s fourth-largest gas producer, supplying 25% of the EU’s natural gas imports.

Sonatrach (the state oil company, Société Nationale pour la Recherche, la Production, le Transport, la Transformation, et la Commercialisation des Hydrocarbures Spa) runs the largest gas field, the Hassi R’Mel, which holds about half the country’s gas reserves (2.4 trillion cubic feet). The problem is that Algeria needs more outlets for gas exports to capitalise on its natural resources, and LNG liquefaction terminals offer more scope for customers such as the US, Japan and Canada. Via two pipelines Algeria already exports gas to Italy and supplies 50% of Spain’s gas.

New terminal

In July 2008 Sonatrach announced that a contract had been awarded for a new LNG liquefaction train. The onshore contract is worth €2.8bn and will involve the construction of a new LNG liquefaction train on a brownfield site in the industrial zone of Arzew adjacent to the existing refinery.

The work was awarded to a joint venture of Saipem / Snamprogetti and Chiyoda on a turn-key basis. The contract will involve the engineering, procurement and construction for a 4.7-million-ton-a-year liquefaction train and associated infrastructure. This is the first time that Saipem has been the main contractor for a large LNG project.

The construction work will begin immediately and is scheduled to be completed in 2012.

Existing capacity

Sonatrach already has an oil refinery at Arzew, which carries out topping and reforming, and has a capacity of 60,000bpd. Opened in 1973, the refinery processes crude piped to it along the Haoud El Hamra / Arzew pipeline. Half of the output is for domestic consumption and half for export.

Alongside the refinery are two gas liquefaction plants – the GL1-Z and GL2-Z – which have recently undergone refurbishment of equipment and de-bottlenecking by Bechtel and IHI and Itochu of Japan. Sonatrach is now looking to expand its gas exporting capacity.

“Algeria has proven natural gas reserves of 4.5 trillion cubic metres.”

The contract to build the third LNG train at Arzew had previously been provisionally awarded to Petrofac (UK) and IKPT (Indonesia) as the lowest bidders. Sonatrach was not happy that the group could provide sufficient guarantees about the capacity and overall cost of the project and consequently they were disqualified. Technip of France also submitted a bid for the project, proposing a 4.88 million tons a year plant at a cost of $5.92bn (this was rejected as too expensive).

Gas feedstock for the new train will be supplied from the Gassi Touil and Rhourde Enouss gas fields.

History

The project was intended to have been developed by Repsol-YPF and Gas Natural of Spain along with a special purpose Algerian company, El Andalus. However the project was withdrawn from this offer in late 2007 because of a delay in planning and implementation and the fact that Sonatrach wanted to fund the new train itself.

Repsol-YPF (60%) and Gas Natural (40%) had already been involved in the integrated discovery and LNG production project from November 2004 to develop and produce 5.2bcm/y of natural gas from the Gassi Touil fields in the Rhourde Nouss-Hamra region. Repsol-YPF and Gas Natural have made significant investment ($2.1 bn) in gas discovery in Algeria and will continue to develop gas resources for the next 26 years according to their original agreement. A further LNG train may be constructed in the future if export demands remain high.

Nearly 565km of the pipeline will be offshore across the Mediterranean Sea, while 272km will be onshore.

The consortium established a new company called Galsi in 2003 to develop the pipeline. Sonatrach owns the largest share of 41.6% interest in Galsi, while Edison has 20.8% interest, Enel has 15.6% interest and Hera has 10.4%. The region of Sardinia owns the remaining 10.4% stake.

The pipeline will have a capacity of eight billion cubic metres each year. The offshore section will be laid at a depth of 2,885m, making the project one of the deepest in the world. The pipeline project is expected to require an investment of €2bn ($2.5bn).

Galsi has signed an agreement with Snam Rete Gas to build, own and operate the Italian section of the pipeline.

Tapping into Algeria’s gas reserves

The project will enable Algeria’s huge gas reserves to be supplied to northern Italy and Europe. Italy is currently dependent on imports to meet 90% of its energy needs. It imports nearly 35% from Algeria, through the Transmed pipeline. The Galsi pipeline is expected to increase the security of gas supply for Italy. It will supply gas from Algeria’s Hassi R’Mel field.

Technical and economical challenges facing Galsi

“The pipeline will have a capacity of eight billion cubic metres each year.”

Construction of the project was originally scheduled to commence in 2012, with completion lined up for 2014. The project, however, faced number of technical and economic challenges, which have delayed its start-up.

The front end engineering design for the pipeline was completed in 2009. In March 2011, Galsi received a positive response from Italy’s Ministry of the Environment for the Environmental Impact Assessment study of the project.

Start of construction has been delayed because of gas pricing issues. Sonatrach has declined to commit to the project until firm contracts are received and the gas pricing issue is resolved. Final investment decision on the project is expected to be taken towards the end of 2012.

Sections making up the gas pipeline

The pipeline has been divided into three sections – the Algeria-Sardinia section, the Sardinian section, and the Sardinia-Tuscany section. The Algeria-Sardinia and Sardinia-Tuscany sections will be located offshore, while the Sardinia section will be onshore.

“The pipeline project is expected to require an investment of €2bn ($2.5bn).”

The Algeria-Sardinia section will be 285km long and will be installed at a maximum depth of 2,824m. The pipeline section will have a design pressure of 182bar and a diameter of 26in.

The Sardinia section will be 272km long. It will have a design pressure of 75bar and a diameter of 48in.

The 280km Sardinia-Tuscany section will be installed at a depth of 878m. It will have a design pressure of 200bar and a diameter of 32in.

The onshore section of the pipeline will have a minimum thickness of 16.1mm, whereas the offshore section will be 37mm thick. The pipes will be made of carbon steel, with polypropylene outer casing used for the offshore section and polyethylene casing for the onshore section. The entire pipeline will have an inner coating of epoxy resin.

Route details for the cross-border project

The pipeline starts from Koudiet Draouche near the Annaba Gulf in Algeria and connects to the Algeria-Sardinia undersea section. In Sardinia, the pipeline reaches Porto Botte, from where it then traverses south to north to reach Olbia.

At Olbia, the pipeline connects with the Sardinia-Tuscany undersea section. It terminates at Piombino in Italy, where the gas will be delivered to the national gas distribution network.

Infrastructure of the Algeria-Sardinia-Italy pipe

“The Sardinia section will be 272km long. It will have a design pressure of 75bar and a diameter of 48in.”

Four studies have been carried out to verify the technical feasibility of the project. These included a feasibility study (2003-2006), marine survey and environmental impact study (2007-2008), Posidonia and SIN (Sites of National Interest) studies (2009), and preliminary assessment of archaeological risk and natural environment impact assessment (2009).

The offshore sections of the pipeline will be laid using S-lay and J-lay methods. The onshore sections will be laid in trenches three metres deep and 2.5m in diameter. A side-boom crane will be used to lay the pipe into the trench. The right of way will be restored to its original environmental conditions after the laying of the pipe.

Advanced techniques will be used to lay the pipeline in environmentally sensitive areas. Post-burying will be done for the sea sections at Porto Botte, Olbia and Piombino. This technique involves laying the pipe on the sea floor and then digging a bed underneath it, using special machinery, into which the pipe gradually sinks. The excavated material is then refilled to cover the pipe.

At the Sardinian north landing area, microtunneling will be used for laying the pipeline. This technique includes the digging of an underground tunnel at a depth of nine metres, into which the pipe will be inserted.

The project also includes the construction of two compressor stations. One of them will be located at Koudiet Draouche. It will bring the gas to the right pressure for injection into the Algeria-Sardinia undersea section.

The second compressor will be located at Olbia to pump the gas into the Sardinia-Tuscany undersea section. It will include two compressor units with a capacity of 26MW each. Office buildings and a maintenance workshop will be located near the compressors.

Contractors involved with Galsi

J P Kenny carried out the Pre-FEED study for the project. The scope of work included identification of optimum pipeline configuration, assessment of feasibility of the pipeline and determination of the project’s timeline and cost.

D’ Appolonia was contracted to study the environmental impact of the onshore section and the offshore sections, located near the coast. EPConsult carried out the deepwater and onshore studies.

Fugro was awarded a €18m ($22.5m) contract to carry out detailed marine surveys. The studies were carried out using Fugro’s Geo Prospector vessel and an Autonomous Underwater Vehicle. Maire Tecnimont, Saipem and Technip carried out the FEED studies for the project.

The project was approved by the Algerian National Oil and Gas Development Agency (ALNAFT) in 2009 and is scheduled to start operations in 2017. It is expected to produce 1.6 billion cubic metres of natural gas per year, which is equivalent to approximately 160 million cubic feet per day.

Partners involved with the Timimoun natural gas project development

The field is owned by Groupement Timimoun (GTIM), a joint venture between Algeria’s state-owned oil company Sonatrach, French company Total and Spanish company Compañía Española de Petróleos (Cepsa). Sonatrach holds 51% interest in the project, while Total and Cepsa hold 37.75% and 11.25% respectively.

Sonatrach will market all of the gas produced in the Algerian project under a marketing agreement signed with the other two partners, while the field operation will be carried out jointly by all the three companies.

Timimoun natural gas project development details

The Timimoun Field Development project, classified as a tight gas reservoir, is among the other natural gas projects in the south-west region of Algeria, such as Touat, Ahnet, In Saleh and Reggane North field projects.

The Timimoun field was explored and appraised from 2003 with the drilling of six wells. A total of 40 production wells have been planned to tap eight structures spread across an area of 2,500km². The scope of the project includes starting operations of the eight structures, the execution of seismic surveys, drilling of the gas wells and construction of natural gas treatment facilities.

Infrastructure at the Algerian natural gas field

The project involves the construction of gas gathering facilities, a gas treatment plant and processing facilities. The planned infrastructure includes the construction of a pipeline intended to be developed by Sonatrach. The 180km pipeline, which will be called the GR5 pipeline, will carry gas from the gas fields in south-western Algeria to Hassi R’Mel gas hub.

The new infrastructure will also support the exploration and development of the Ahnet natural gas project located in the Salah region.

Contractors involved

Samsung Engineering was contracted for $800m in February 2014 to undertake the engineering, procurement, construction and pre-commissioning of the gas treatment facilities on a lump-sum-turn-key basis. It will build the pipeline and a central processing facility with a capacity of 177 million standard cubic feet per day (MMSCFD), as part of the contract.

CGGVeritas was awarded a contract in 2012 by Groupement Timimoun (GTIM) to perform 3D vibroseis survey at the project site.