Eurasia Press & News
Europe entered 2025 at a level of energy security that would have seemed out of reach only a few years ago. Gas storage exceeded 70% in January, an exceptionally high level for the season, while overall demand remains roughly 15% lower than in previous years. This decline is not temporary but the result of several factors that have permanently reshaped the continent’s energy landscape. Mild winters have reduced heating needs, the energy‑saving policies adopted after 2022 have now become embedded in industrial and household behavior, and the gradual de‑industrialization in certain sectors, especially in Germany, has lowered demand in ways that will be difficult to fully reverse.
At the same time, EU domestic production continues to shrink. At around 40 bcm in 2024, it recorded a 12.4% drop compared with the previous year, confirming that Europe has now entered a permanent phase of import dependence of more than 85%. With consumption stabilizing around 360–370 bcm per year, the need to diversify sources and routes remains critical not only for security reasons but also to maintain competitive prices in a market still vulnerable to global fluctuations.
Western Europe
The backbone of Western Europe’s gas supply continues to be Norway. Through its North Sea pipelines, it reliably delivers 120–124 bcm per year, supported by long‑term contracts, high technical availability, and a stable political environment. These flows account for nearly 30% of Europe’s consumption and anchor the continent’s overall energy balance. Alongside this steady pillar, the United States has emerged as Europe’s leading LNG supplier, providing 55–60 bcm annually. Its flexible deliveries and spot‑pricing mechanisms enable Europe to compete effectively with Asia for cargoes during periods of heightened demand. Completing this trio of core suppliers is Qatar, which ships 15–20 bcm of LNG each year and maintains a consistent presence through long‑term contracts, with additional volumes expected once the North Field expansion comes online after 2027.
The remaining roughly 160 bcm that Western Europe requires is sourced from a diverse set of suppliers. Algeria delivers around 25–30 bcm per year to Italy and Spain through the TransMed and Medgaz pipelines, although volumes fluctuate depending on domestic Algerian demand and production constraints. Azeri gas adds another 10 bcm annually via the TAP pipeline, with the option to double capacity to 20 bcm in the coming years. Smaller but steady LNG contributions come from Nigeria (typically 8–12 bcm per year) and Trinidad & Tobago (around 3–5 bcm), providing additional flexibility to the European system. Russian gas, once dominant, now plays a marginal role: flows through TurkStream have fallen to 10–12 bcm per year, while Russian LNG deliveries to Europe hover around 14–17 bcm, well below pre‑2022 levels.
Western Europe has effectively transformed into an LNG‑centric market, with LNG now accounting for nearly 40% of total gas imports, compared with less than 20% a decade ago. This shift has elevated the strategic importance of regasification terminals across the region. Facilities in France (Dunkerque, Montoir‑de‑Bretagne, Fos), Spain (with its seven terminals and over 60 bcm/year of capacity), the Netherlands (Gate terminal and Eemshaven FSRU), and the United Kingdom (Isle of Grain, Milford Haven) operate with consistently high availability. Together, they form a network of critical entry points capable of receiving more than 150 bcm per year of LNG and redistributing it into the European grid, enabling cargoes to be rerouted rapidly toward Central and Northern Europe depending on market conditions.
Central Europe
The supply of Central Europe now rests on three structural axes that have fundamentally reshaped the region’s energy geography and reduced its vulnerability to single‑source dependence.
The first axis is the Krk LNG terminal in Croatia, with a capacity of 6 bcm per year. Croatia, despite consuming only 3 bcm annually, has become one of the region’s most strategic nodes. The Krk FSRU supplies Hungary, Slovenia, Slovakia, and part of Austria, effectively creating a new north–south LNG corridor that bypasses traditional east–west routes dominated by Russia. Its location allows gas to flow deep into Central Europe and provides a flexible alternative during market disruptions or pipeline outages.
The second axis is the Trans Adriatic Pipeline (TAP), which brings 10 bcm per year of Azeri gas into Europe, with the option to expand to 20 bcm. TAP is not just another pipeline; it is the only non‑Russian, non‑LNG conduit feeding Southern and Central Europe. Its potential expansion would materially strengthen supply security for Italy, the Western Balkans, and Central Europe by adding a second, scalable non‑Russian pipeline corridor.
The third axis is the Baltic Pipe, delivering 10 bcm per year and linking Poland directly to Norwegian production via Denmark. This connection has allowed Poland, consuming around 20 bcm annually, to almost eliminate Russian imports while reinforcing its emerging role as a regional hub for the Baltic states and parts of Central Europe. The Baltic Pipe also integrates Poland more tightly into the North Sea supply system, which is Europe’s most stable and politically secure source. Together, these three axes form a new triangular backbone for Central Europe’s energy security: Krk provides LNG flexibility from global markets, TAP brings pipeline gas from the Caspian, and Baltic Pipe anchors the region to Norwegian stability.
Italy has now become an integral part of this stabilizing network. With annual consumption of around 70 bcm, it has emerged as one of Europe’s most important gas hubs. It sources these volumes mainly from Algeria via TransMed, from TAP, and from its three LNG terminals in Ravenna, Venice, and La Spezia, which together add more than 20 bcm per year of capacity. With this diversified mix, Italy not only secures its own supply but also functions as a critical transit platform, sending up to 10 bcm per year to Central Europe through its interconnections with Switzerland and Austria. This role is more significant than it appears: Italy effectively links North African pipeline gas, Caspian pipeline gas, and global LNG to the heart of the European grid. By doing so, it provides a third southern LNG gateway alongside Greece and Croatia, creating a redundant, multi‑entry architecture that allows Europe to absorb shocks, reroute flows, and maintain supply even when one corridor is disrupted. Italy’s position therefore strengthens not only Southern Europe’s resilience but also the entire continental system, acting as a balancing node between east–west and north–south flows and reducing the structural dependence on any single supplier or route.
Eastern Europe and the Balkans
Here the picture is more complex, because the region is far from homogeneous: countries differ sharply in their levels of domestic production, their historical dependence on Russia, their access to alternative routes, and the maturity of their infrastructure. Romania is the only country with substantial domestic output, around 10–11 bcm per year, which covers almost all of its consumption. Black Sea fields such as Neptun Deep are expected to further boost production after 2027, giving the region a rare pocket of energy autonomy. Serbia, by contrast, consumes around 3 bcm per year and remains heavily dependent on Russian gas delivered through TurkStream, with very limited options for diversification. Hungary, with a demand of roughly 9 bcm per year, is the largest TurkStream recipient in the region and continues to rely on Russian volumes, supplementing them with gas from the Krk LNG terminal and reverse flows from Slovakia and Austria.
Greece, consuming around 5 bcm annually, plays a very different role: it has become a regional entry point thanks to Revithoussa, the new Alexandroupolis FSRU, and TAP, enabling flows northward to Bulgaria, Serbia, and Romania. Bulgaria, with consumption of about 3 bcm per year, now depends on a combination of IGB, TurkStream, and LNG imports routed through Greece, having eliminated the direct dependence on Russia. The result is a patchwork system in which each country operates under different constraints and opportunities, making the region’s energy landscape far more fragmented and therefore more complex than that of Western or Central Europe.
Limitations and bottlenecks of the suppliers
This new distribution confirms that, with demand remaining low and storage levels unusually high, Europe does not need additional LNG regasification infrastructure before 2030. The challenge is no longer about expanding import capacity but about reinforcing the existing network of interconnections and regional hubs, from Revithoussa and Alexandroupolis to Krk, Italy’s LNG terminals, and the Baltic Pipe. Europe already possesses more than 260 bcm per year of regasification capacity, far exceeding its foreseeable needs. The real constraint now lies in transporting gas from coastal entry points to the interior. Strengthening pipelines, reverse‑flow capabilities, and cross‑border links matters far more than building new terminals.
The limitations and bottlenecks of the major suppliers differ considerably. In the United States, LNG export capacity currently stands at around 160 bcm per year and is projected to grow by another 145 bcm by 2029. Yet short‑term tightness persists, driven by scheduled maintenance, strong Asian demand, and uncertainty around federal permitting. At the same time, the engineering cost of new liquefaction capacity has risen sharply. The steel‑intensive nature of LNG trains, the need for specialized cryogenic equipment, and the global shortage of large‑scale compressors and heat exchangers have all pushed capital costs higher. Inflation in construction labor, particularly welders, pipefitters, and technicians certified for cryogenic systems, adds further pressure, while higher interest rates increase the cost of financing multi‑billion‑dollar projects. As a result, the capital cost of new liquefaction plants has climbed to roughly $0.9–1.3 billion per bcm of annual capacity. Liquefaction fees have also risen to $0.095–0.105 per cubic meter, reflecting both higher operating costs and the need to secure long‑term returns for investors. Expanding capacity by 150 bcm per year would therefore require a total investment of $135–195 billion—figures broadly consistent with US–EU commitments to increase European LNG imports and replace Russian volumes.
Norway remains Europe’s most stable and predictable supplier, but its output is approaching the natural limits of its mature North Sea fields. Although Norway is primarily a pipeline supplier, it also exports small but steady LNG volumes (6-7 bcm) from the Hammerfest/Melkøya facility, adding an additional layer of flexibility to Europe’s supply mix. These LNG exports are modest compared with pipeline flows, but they underline Norway’s ability to serve both the continental grid and the global LNG market. Most of the large reservoirs discovered in the 1970s and 1980s are now in decline, and although enhanced recovery techniques can slow this trend, they cannot fully reverse it. The Norwegian government has launched new licensing rounds and approved additional field developments in the Barents and Norwegian Seas, which should help stabilize production in the second half of the decade. These new projects, smaller, more technically complex, and often located in harsher environments, are expected to offset part of the natural decline but not to recreate the production peaks of previous decades.
Qatar, meanwhile, is expanding the North Field, though the additional LNG volumes will only materialize after 2026–2028, given the long construction lead times for new liquefaction trains and offshore platforms. Algeria faces declining output from aging fields and rising domestic consumption, which reduces the volumes available for export and contributes to volatile LNG shipments. Egypt has moved in the opposite direction: once an emerging LNG exporter, it has become a net importer due to falling production, limited new discoveries, and rapidly growing domestic demand driven by population growth and electricity needs.
As for Russia, its theoretical ability to restore gas exports to the EU remains high on paper, but the practical conditions for such a return are absent. Re‑establishing significant flows would require political and institutional changes that are nowhere on the horizon: the lifting of sanctions, new transit agreements with Ukraine and Central Europe, full alignment of payment mechanisms with the EU/G7 framework, and the signing of new long‑term contracts with European buyers. Only under such circumstances could Russian exports return to the 120–126 bcm per year delivered by pipelines and the 49–54 bcm per year supplied as LNG before 2022.
Even if there were a limited easing in US–Russia relations, the incentives of the two sides remain fundamentally asymmetric. The United States, now Europe’s largest LNG supplier, has every interest in maintaining stable prices and predictable market conditions but none in facilitating a Russian comeback that would erode the market share of US LNG in Europe. The European Union, for its part, has institutionalized and politically entrenched a strategy of permanent disengagement from Moscow. Diversification of supply expanded LNG infrastructure, and new interconnections have become core elements of Europe’s energy architecture, making a return to large‑scale Russian imports not only difficult but also structurally incompatible with the direction of EU policy.
For Russia, the situation is equally complex. The redirection of production toward Asia, primarily China via the Power of Siberia pipeline and potential future expansions, has shifted Moscow’s strategic priorities. Russia has invested heavily in building a new eastern market, but this market cannot immediately absorb the volumes once destined for Europe. At the same time, Moscow refuses to comply with the European payment framework, which requires transparency, adherence to sanctions, and the avoidance of mechanisms that could circumvent the G7 price cap.
The only scenario that could open a narrow window for rapprochement would involve US companies participating in Russian production or trading structures, providing political cover and mutual economic incentives. Such an arrangement could create a form of “co‑management” of export flows, with the United States retaining influence over volumes and Russia gaining access to Western technology and financing. Yet even this hypothetical scenario would collide with the reality of Europe’s new energy system: expanded LNG capacity, strengthened regional hubs, upgraded interconnections, and a political commitment to diversification have created an environment in which Russia can no longer operate as the monopoly supplier it once was.
Conclusion
Europe’s energy security now rests on a new triptych: predictable gas pipeline flows with some LNG from Norway, LNG imports from the United States and Qatar, and the regional LNG hubs that have emerged as critical entry points, Greece, Croatia, and Italy. These three hubs, anchored in the infrastructures of Revithoussa–Alexandroupolis, Krk, and Ravenna–Venice, allow Europe to redistribute cargoes efficiently and push regasified LNG deep into the continent from the south. Shortfalls from Algeria and Egypt are increasingly absorbed through TAP, the IGB, reverse flows along the Trans‑Balkan corridor, and the flexibility provided by the three southern LNG gateways.
In this new architecture, the TTF has effectively become the international “signal” that determines where LNG cargoes will move. Europe, operating without extensive long‑term contracts and relying heavily on the spot market, must keep the index at levels capable of attracting cargoes away from Asia. When Asian demand rises, the TTF must rise with it to preserve Europe’s pull on global LNG flows, with immediate and visible consequences for energy costs faced by households and businesses. Europe’s security, therefore, is no longer defined only by molecules and pipelines but by its ability to remain competitive in a globalized, price‑driven LNG market.
