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.

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The appeal for early gas storage comes against a backdrop of escalating geopolitical tensions and heightened market volatility. Prices have risen sharply following US President Donald Trump’s ultimatum to Iran to reopen the Strait of Hormuz within 48 hours, a move that intensified uncertainty in global energy markets. Iran, in response, threatened additional energy infrastructure and desalination plants across the Gulf region. On 23rd March 2026, Trump announced he would refrain from targeting energy infrastructure for five days. Jørgensen emphasized the importance of coordinated preparation, stating, We are still in the early stages of the storage injection season, but it is essential that we start our preparations in time for next winter and in a coordinated manner, as the EU seeks to strengthen early gas storage planning.

The European Commission has introduced greater flexibility in storage rules to support this effort. Member states are now permitted to distribute refilling targets over an extended timeframe and adapt them to changing market conditions. Jørgensen stated in his letter, This flexibility can help reduce the gas demand at times when the supply is tense and ease the pressure on gas prices in Europe. We have also learned the pitfalls of uncoordinated action. Despite ongoing challenges, the Commission maintains that the EU is much better prepared than in 2022, when Russia’s invasion of Ukraine triggered a severe supply shock and price surge. Current regulations require storage facilities to reach 90% capacity by 1st November, although the Commission is encouraging countries to aim for 80% earlier in the season, with allowances for reductions to 75% or even 70% under difficult conditions.

Storage levels currently stand at around 30%, below last year’s figures and significantly under the 10-year average of 58%. Against this backdrop, Ursula von der Leyen has outlined additional measures to contain rising electricity costs, following discussions among EU leaders in Brussels on 19th March 2026. These include reforms targeting taxation, grid efficiency, and carbon costs, alongside potential adjustments to the Emissions Trading System (ETS). Governments across the bloc are simultaneously deploying tax relief, subsidies, and market interventions to shield consumers and businesses, as early gas storage strategies remain central to stabilising Europe’s energy outlook.

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According to OEUK’s latest report, oil and gas continue to account for around 75% of the UK’s energy requirements and are projected to meet roughly one-fifth of demand by 2050. However, as domestic production declines and demand rises, the report highlights an increasing exposure to price volatility. David Whitehouse, chief executive of OEUK, stressed the urgency of the situation, stating that the UK is in dire need of greater supplies of secure, domestically produced energy including oil and gas, which will remain a critical part of the UK energy system and economy for decades. The group is urging policymakers to reconsider the current stance on North Sea drilling and reassess restrictions on offshore exploration licences imposed last year.

Under existing regulations, operators are permitted to expand output only within already licensed areas or in adjacent zones, a limitation the industry argues could constrain future production. OEUK is also advocating for changes to the fiscal framework, including the removal of the Energy Profits Levy (EPL) by 2026, four years earlier than planned. In its place, the proposed Oil and Gas Price Mechanism would apply a 35% tax when prices exceed a defined threshold, compared with the current 78% rate under the windfall tax. The industry group believes such reforms could unlock £50bn in fresh investment and reinvigorate North Sea drilling activity.

Political divisions remain evident. The Conservative Party wants both the removal of the EPL and the reversal of the licensing ban, while also supporting approval for the Rosebank and Jackdaw fields. However, a ruling by the Court of Session in Edinburgh, following a legal challenge from Uplift and Greenpeace, found that environmental impacts had not been adequately assessed, requiring developers to seek fresh approval.

Meanwhile, researchers at the University of Oxford have questioned the economic case for expanded North Sea drilling, concluding that even maximum extraction would deliver limited cost savings compared with accelerating the transition to renewable energy.

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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.

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This transformation comes as Europe restructures its energy network, replacing Russian pipeline gas with liquefied natural gas and elevating the importance of transit countries. Greece’s strategic location at the crossroads of the Balkans and the eastern Mediterranean is central to its emergence as a European gas hub, even as nations like Poland, Croatia and Lithuania expand their own LNG capabilities.

State-backed gas-grid operator Desfa SA is driving this shift through the development of the Vertical Gas Corridor, designed to connect Greece’s system with networks in countries such as Romania and Ukraine while enhancing regional transport capacity. A new compressor station launched in northern Greece in November has already strengthened LNG import volumes and boosted exports to neighboring markets. According to Mitsotakis, the infrastructure has enabled Greece to deliver gas to Ukraine during periods of acute strain, reinforcing its role as a European gas hub and a pillar of energy security in southeastern Europe. It also “ties us geopolitically with the U.S.,” he said.

The country’s LNG imports underline this growing role. The United States emerged as Greece’s main supplier in 2025, with volumes reaching 26.56 terawatt-hours, nearly double the previous year and accounting for more than 86% of total imports. Industry leaders say the increasing reliance on LNG is cementing Greece’s standing as a European gas hub.

“The use of LNG is picking up pace and making up a much larger share of supply in our region, and Greece has become a hub,” said Helleniq Energy Holdings SA Chief Executive Officer Andreas Shiamishis. He also added that there is potential for a third LNG import facility. Helleniq Energy Holdings SA is advancing plans for a floating storage and regasification unit in Thessaloniki, with a final investment decision expected in 2026, complementing existing infrastructure at Revithoussa and offshore Alexandroupolis.

Beyond gas, executives see broader opportunities tied to Europe’s energy transition. Chief executive of Public Power Corp., Georgios Stassis noted, “We’re in the heart of the energy transition in the region and we can have the best returns,” pointing to operations spanning Greece, Romania, North Macedonia, Italy and Bulgaria.

With expanding solar and wind capacity turning Greece into a net electricity exporter, the country is also positioning itself to import and transmit renewable energy into Europe, including through projects such as Gregy.

The post Greece Seeks Key European Gas Hub Role Amid Russia Phase-Out appeared first on Oil&Gas Advancement.

The Han Tervel block, central to the Black Sea exploration project, was awarded an exploration license in 2025 with an initial five-year validity period. The offshore area spans approximately 4,000 km² and lies south of the Han Asparuh block in the Bulgarian sector of the Black Sea. OMV Petrom said the project reinforces its existing regional portfolio and reflects its continued commitment to expanding offshore activities in the area.

Christina Verchere, CEO of OMV Petrom, said that the project strengthens the portfolio of the organization, while strengthening their commitment to the region. By participating in the Black Sea exploration project, the company is also applying its long-standing offshore expertise to new opportunities within the basin.

The next stage of the Black Sea exploration project will begin with the acquisition and detailed evaluation of 3D seismic data across the license area. These seismic studies are expected to provide a clearer understanding of subsurface geological structures and help determine the potential for hydrocarbon resources. Depending on the results of this seismic analysis, the consortium partners will assess the feasibility of moving forward with exploration drilling activities in later phases. Financially, OMV Petrom will fund project expenses and investments in proportion to its 25% stake. This commitment includes covering a share of historical expenditures as well as future operational costs tied to exploration activities.

Cristian Hubati, OMV Petrom Executive Board member responsible for Exploration and Production stated that the organization hopes for a productive partnership with Shell and TPAO to unlock new opportunities in the area. OMV Petrom’s involvement in the Black Sea exploration project builds on the company’s long-standing presence in the region.

The firm has been active in the Black Sea for four decades, with a portfolio that includes exploration, development, and production operations across Romania and Bulgaria. In addition, OMV Petrom serves as operator of Neptun Deep, currently the largest natural gas project in the European Union.

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A central component of the Rijeka Refinery upgrade project is the installation of a new Delayed Coking Unit along with supporting processing facilities. With these additions, the refinery can now process up to four million tons of crude oil annually, including heavier crude grades. The upgraded configuration is designed to optimize refining operations, allowing the plant to generate greater volumes of high-value petroleum products from the same amount of crude input. As a result, diesel production at the facility is expected to increase by approximately 30 per cent. Another operational change brought by the project is the elimination of the need to import vacuum gas oil (VGO), which was previously sourced largely from Russian origin.

The scale of construction involved in the Rijeka Refinery upgrade project was substantial. The refinery’s new units required more than 10,000 tons of steel, along with approximately 60,000 cubic meters of concrete. The completion ceremony was attended by representatives from the Croatian and Hungarian governments, ambassadors, members of local communities, and executives from INA and MOL Group, highlighting the national and regional significance of the project.

Ahead of the ceremony, INA also signed a 15-million-euro grant agreement under the National Recovery and Resilience Plan for the construction of a green hydrogen plant at the refinery site. As part of this initiative, the company plans to invest more than 60 million euros in a 10-megawatt (MW) electrolyser and an 11 MW solar plant. The hydrogen produced will be used both in transportation and refinery operations. Completion of the hydrogen facility is planned for the end of 2026, with production expected to begin in 2027.

Commenting on the development, Zsuzsanna Ortutay, President of the Management Board of INA, stated that the refinery will facilitate the company’s transition to a lower-carbon economy.” Croatian Minister of Economy Ante Šušnjar also addressed the project, expressing hope that the Rijeka Refinery will “operate stably, sustainably, and at full capacity, benefitting Croatia’s economy, energy system, and our partners in the region.”

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The availability of gas volumes for the region has recently declined as the ripple effects of conflict in the Middle East spread through global energy markets. Transnistria’s economic development ministry acknowledged the situation, stating: “In connection with events in the Middle East, there have been critical disruptions in gas supplies,” and adding that “Sharp cuts in gas volumes have led to limits on usage for commercial purposes or thermal heating.” The same report cited the speaker of Moldova’s parliament as saying that Transnistria only had gas for several days. The tightening supply environment reflects broader pressures in Europe, where natural gas prices have surged dramatically. Prices have doubled in less than a week, with the The Dutch Title Transfer Facility (TTF) benchmark intraday contract topping 60 euros per megawatt-hour earlier this week.

The spike in prices followed Iranian strikes on Qatari LNG production facilities, prompting QatarEnergy to shut down its entire LNG production system. Shortly afterward, the company declared force majeure on LNG exports. Because Qatar accounts for roughly a fifth of global LNG flows, the disruption immediately affected markets and intensified the European gas supply crunch. Europe remains particularly exposed to such supply shocks. Since reducing reliance on Russian pipeline gas, the European Union has turned increasingly to seaborne LNG imports, with Qatar among its largest suppliers. Although some observers point to abundant American liquefied gas supplies, those volumes are unlikely to be sold at prices favorable to buyers. With Qatar’s LNG production suspension, control of the liquefied gas market has shifted firmly toward sellers, raising the prospect of further price pressure for European importers.

Smaller EU members and countries such as Moldova face especially acute vulnerability during an European gas supply crunch because their economies have less financial flexibility to manage higher energy costs. Yet the potential impact could be equally severe for larger economies like Germany, which forms a central pillar of the European Union and whose industrial sector relies heavily on stable energy supply. Moldova itself aims to join the bloc by 2030, making regional energy stability increasingly important. Qatar supplies between 12% and 14% of the European Union’s natural gas. Even with lower direct dependence, Europe remains exposed to price shocks and supply disruptions across the LNG market, meaning the current European gas supply crunch could reverberate across the continent from Transnistria to the UK.

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Qatar, responsible for roughly 20 percent of global LNG supply, suspended production on Monday after its facilities were attacked. At the same time, the conflict has significantly reduced the number of ships passing through the Strait of Hormuz, a vital shipping route along Iran’s southern coastline. Europe, already heavily dependent on LNG imports, has been particularly sensitive to disruptions in supply. The region increased its reliance on shipments from the United States and Norway after Russia curtailed pipeline deliveries in 2022 following its invasion of Ukraine. Qatar holds the world’s third-largest natural gas reserves and has been working to roughly double its export capacity by 2032 to meet growing demand, according to Wood Mackenzie. Major buyers of its LNG include China, India and South Korea.

Over the last decade, the global LNG trade has evolved significantly, strengthening the position of Western energy firms. Companies like Cheniere have developed eight terminals in the United States where natural gas is cooled into liquid form so it can be transported on specialized oceangoing tankers. Large oil and gas companies including Shell, Total and Exxon purchase much of this LNG under long-term contracts before reselling it to customers worldwide. The price impact of Qatar’s supply disruption has been dramatic: the main Asian LNG benchmark has surged roughly 91 percent since the end of last week, while the European benchmark has risen about 44 percent.

According to Jason Feer, head of business intelligence at Poten & Partners, the price at which Western companies can now sell LNG in Europe is about double the cost of acquiring and delivering the fuel, thus setting the stage for Western energy firm profits. Only a week earlier, those companies were earning revenue approximately 27 to 28 percent above their costs.

Higher LNG prices could pose challenges for importers across Asia and Europe, particularly if current levels persist. European gas inventories are relatively low after substantial consumption during the winter heating season. Still, Ditte Juul Jørgensen, the Director General for energy at the European Commission, wrote in a LinkedIn post that European officials were monitoring the situation but believed prices would not surge to the extreme levels seen in 2022. Meanwhile, Geoffrey Pyatt, who managed LNG issues as an assistant secretary of state during the Biden administration, noted that U.S. exports have expanded sharply in recent years. The United States has become the world’s largest LNG exporter thanks to rising gas production in states such as Texas and Pennsylvania, with Australia also playing a major role. According to the Energy Information Administration, U.S. suppliers signed contracts to sell more LNG last year than in any year since 2022, and export capacity is expected to nearly double by 2031 compared with December 2025.

As the largest LNG trader in the world, Shell may be among the top beneficiaries  if oil and gas prices do remain high for a long time. Meanwhile, TotalEnergies was the biggest seller of American LNG last year. Furthermore, in 2025, Cheniere was the US’s biggest producer of LNG. ExxonMobil claimed that although it has enough of natural gas and oil in the US, it has little control on prices.

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The latest review follows an earlier ad hoc session of the Oil Coordination Group on 25th February 2026, when the EU examined the implications of supply disruption in the Druzhba pipeline caused by Russian attacks on Ukraine’s energy infrastructure. At that time, Member States similarly concluded that there was no immediate security of supply risks. In response to the Druzhba pipeline disruption, Hungary and Slovakia released portions of their emergency oil stocks, which are maintained as reserves, while simultaneously increasing reliance on alternative supplies. These measures formed part of coordinated efforts to safeguard a stable oil supply within the region.

All EU countries maintain emergency stocks of oil and petroleum products to address potential supply shocks. Given that approximately one-quarter of the energy consumed in the EU is derived from natural gas, ensuring continuity of supply remains critical for households and businesses alike.

The Commission underscored that it will persist in monitoring developments closely and maintain regular communication with Member States and market participants. In case a prolonged closure of the Strait of Hormuz or further disruptions arise affecting flows, the EU will reassess its security of oil and gas supply. For now, authorities continue to report a stable oil supply and steady gas storage levels, signalling resilience in the face of external pressures.

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