A document outlining the agenda indicates that the European Commission’s Cyprus Presidency will raise the issue of indigenous gas resources as a potential mechanism for collective price stability across the Union. This comes at a time when the bloc is grappling with an ongoing energy crisis, exacerbated by market disruptions following Russia’s withdrawal from the European market in 2022 and volatility in the global liquefied natural gas (LNG) market, particularly due to recent geopolitical tensions.

While the EU has made significant strides in reducing its reliance on Russian gas, transitioning from 45% to approximately 12% since the conflict in Ukraine began, the bloc’s exposure to the global LNG market’s fluctuations has become more pronounced. The document poses a direct question to ministers: “Given the current price shocks and the volatility of the global LNG market, how do you see the role of indigenous gas resources as a collective mechanism for price stability across the Union?” This highlights the immediate challenge posed by higher energy costs, which have already added an estimated €24 billion to EU import expenditures.

Despite the EU’s stated climate ambitions, with a continued focus on ending oil and gas drilling, some industry experts and analysts suggest that renewable energy sources alone may not be sufficient to meet energy demands in the near future. Consequently, several member states are reportedly becoming more receptive to expanding their natural gas production capabilities.

Examples of existing domestic gas potential within the EU include Romania’s Neptun Deep project, which has been extracting gas from the Black Sea since March 2025. Greece has initiated its first offshore exploratory drilling campaign for natural gas in nearly four decades, with operations targeting potential reserves in the Ionian Sea slated to commence in early 2027. Italy is also considering the revival of offshore oil and gas exploration projects that were previously suspended. Other noted areas of potential include Poland’s developments in the Baltic Sea and wider cooperation in the North Sea.

Croatia recently finalized an agreement to enhance gas pipelines and energy infrastructure across the Balkan region. Furthermore, industry assessments suggest that Cyprus possesses significant untapped reserves, with geological data indicating approximately 324.1 billion cubic metres of gas, a volume comparable to the EU’s average annual consumption. The conversation around increased domestic gas drilling is occurring alongside efforts to secure energy supplies amidst surging prices.

However, the prospect of expanded gas drilling has also drawn criticism from environmental organizations. Climate Action Network Europe has called for the adoption of a binding annual target to reduce gas demand by 7%. Industry representatives, meanwhile, emphasize the continued importance of gas in Europe’s energy mix, particularly for ensuring security of supply, maintaining system flexibility, and supporting industrial competitiveness during the ongoing green transition.

Andreas Guth, secretary-general of Eurogas, stated that “Ensuring Europe’s strategic autonomy will require a diversified energy mix, including domestic natural gas production alongside the accelerated scale-up of both domestic and imported renewable and low-carbon gases such as biomethane and hydrogen.”

He also stressed the importance of adapting and repurposing existing infrastructure to safeguard long-term investments while progressing towards climate neutrality.

EU leaders have consistently encouraged households and businesses to conserve energy, while also asserting that Europe’s long-term energy independence hinges on the expansion of domestic renewable power generation. Nevertheless, experts acknowledge that the full integration of renewable sources like wind and solar power necessitates substantial investments in grid upgrades and large-scale energy storage infrastructure, a process projected to span several years and require trillions of euros. Energy Commissioner Dan Jørgensen remarked in March that “In the short and medium term, we will still need quite a lot of gas, and that need has only increased with our decision to phase out Russian gas.” The discussion on domestic gas drilling aims to balance these immediate needs with long-term energy strategy.

The Druzhba pipeline has emerged as one of Europe’s most politically sensitive energy corridors following a Russian drone strike that damaged infrastructure in western Ukraine, halting Russian oil supplies to Hungary and Slovakia. The disruption underscored the strategic importance of the Druzhba pipeline for regional energy security.

Developments around the Druzhba pipeline coincided with political progress in Brussels, where EU ambassadors approved a financial package intended to support Ukraine.  The EU had agreed to the loan last ⁠year to maintain Ukraine’s liquidity through 2026 and 2027, but approval had been delayed after Hungary’s Prime Minister Viktor Orban and the Slovak government blocked it. Both governments accused Ukraine of slowing repairs to the pipeline, an allegation Kyiv denied. Hungary and Slovakia remain heavily dependent on Russian oil, and Orban has consistently shown support for Russia, making the Druzhba pipeline a focal point in broader geopolitical tensions.

The situation shifted after Hungary’s parliamentary election on 12th April 2026, when Viktor Orban lost power. The leader of the ⁠winning party, Peter Magyar, has said he will no ‌longer block the EU funds for Kyiv, though he is only expected ⁠to take power next month. Meanwhile, the Druzhba pipeline retains significant capacity, ranging from 1.2 million to 1.4 million barrels of oil a day, with potential to increase to 2 million barrels. However, actual flows have dropped sharply due to Western sanctions and repeated disruptions linked to drone attacks, limiting its operational output.

Separately, Germany confirmed that ⁠no Kazakh crude would be delivered to its PCK Schwedt refinery from May 2026. This follows reports from industry sources that Russia was preparing to halt Kazakhstan’s oil exports via the Druzhba pipeline, adding another layer of uncertainty to an already strained supply route. The developments highlight the continuing volatility surrounding the Druzhba pipeline and its role in Europe’s evolving energy landscape.

Alongside this acquisition, Enagás has finalized the sale of a 40% stake in Enagás Renovable to Hy24 for €48 million, while maintaining a 20% holding. These parallel developments signal a broader strategic adjustment, as the company places increased emphasis on regulated infrastructure assets while reallocating capital from early-stage renewable initiatives. The Teréga investment aligns with Enagás’s long-term focus on building a stronger presence among European transmission system operators, particularly at a time when cross-border gas flows and infrastructure coordination are gaining importance due to ongoing energy security challenges. This positioning further supports its European network expansion objectives across the region.

The partial divestment from Enagás Renovable indicates a shift in the company’s approach to the hydrogen sector. Rather than maintaining a broad development role, Enagás appears to be focusing on core infrastructure such as transport networks and pipeline systems, where it holds established expertise. This approach is reflected in its involvement in the Spanish Hydrogen Backbone Network and its participation in the H2Med corridor, which connects Iberia with wider European markets. These initiatives remain integral to its European network expansion, particularly as hydrogen infrastructure becomes increasingly relevant within Europe’s evolving energy mix.

These developments underscore the ongoing importance of gas infrastructure even as Europe accelerates its decarbonization efforts. The Teréga transaction highlights continued consolidation among European TSOs, reinforcing the role of integrated systems capable of handling both natural gas and low-carbon alternatives such as hydrogen.

“One of the Directorate’s most important priorities is to support measures that can curb the expected decline in production from the NCS. There is a significant gap between the identified EOGR opportunities and the few pilot projects that have actually been pursued,” said Ove Bjørn Wilson, senior reservoir engineer at the Norwegian Offshore Directorate.

In 2026, the Ministry of Energy tasked the Directorate with “contributing to realise profitable development using advanced EOGR methods”. As part of this mandate, an internal task force has begun reviewing projects that remain uncompleted or unimplemented, building on earlier research that estimated a theoretical recovery potential of 350-700 million standard cubic metres of oil equivalent through advanced enhanced oil and gas recovery techniques. Despite this promise, uncertainty remains regarding how much of this volume can be translated into commercially viable production.

“There is still uncertainty as to how much of this could actually yield profitable increased recovery. We could be talking about quantities that match the entire production from the Johan Sverdrup field. This could have a significant impact on activity on the NCS, and yield vast revenues for both the industry and society in general,” Wilson said.

Historically, several enhanced oil and gas recovery methods have been explored for specific fields but were ultimately shelved. Challenges linked to technical feasibility, strict profitability thresholds, environmental cost considerations, and limited access to suitable injection sources contributed to these decisions. However, the experience of applying enhanced oil and gas recovery offshore in other regions has demonstrated that such approaches can be both technically viable and economically attractive under conditions similar to those found on the NCS.

“This shows that EOGR is technically feasible and profitable under conditions comparable to the NCS. In our efforts now, we’ll be thinking outside the box, looking at alternatives we haven’t previously investigated,” said  Wilson.

Against this backdrop, the Norwegian Offshore Directorate is now evaluating which fields possess the geological and technical characteristics necessary for an enhanced oil and gas recovery pilot. In parallel, the Directorate is examining the optimal stage in a field’s lifecycle for implementing such measures, recognising that timing plays a crucial role in achieving profitability.

“The objective is to identify fields that are well-suited for profitable production with the aid of advanced methods, which the operators should examine in more detail. This is urgent work, as the development of the NCS is already mature,” he added.

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.

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.

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.

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.

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 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.