Record renewables build, four times Germany’s grid-scale battery fleet, and the pumped-hydro topography Northwest Europe cannot replicate. Southeast Europe is building a low-cost power system, and compute is already following it.
Every winter, European energy analysis follows the same script. German gas storage levels. Nordic hydro reservoirs. Iberian solar records. French nuclear availability. Peak price spikes in the northwest, and the familiar conclusion that European industry can no longer compete on energy cost.
The analysis is accurate. It is also looking in the wrong direction.
Southeast Europe sits between two of the most consequential energy geographies on the planet. To its east and south lie the Caspian, the Black Sea, and the Middle East: resource-rich and geopolitically turbulent. To its west and north lies an industrialized Europe that is energy-hungry, structurally expensive, and steadily losing manufacturing capacity as a result.
EU industrial electricity prices remain more than double those in the United States. Energy-intensive sectors have shed 1.5 million jobs since 2008, with output in some falling 40% since 2018. The European Commission’s own vocabulary has shifted from green transition to affordable energy, which tells you how the problem is now understood in Brussels. The question that follows is where inside the single market cheap, firm, well-sited power is actually being built.
The answer is the part of the continent that gets the least coverage. Southeast Europe is adding renewable capacity at record rates, holds more grid-scale battery storage than Germany, sits on the best pumped-storage topography in Europe, and is converting closed coal regions into data center campuses. It is doing all of this at construction and labor costs a fraction of the German equivalent.
At Scalefocus, we work with energy companies across the Balkans, Central Europe, and the Eastern Mediterranean: transmission operators, traders, utilities, IPPs, and industrial energy users. Our teams sit inside the systems that run these markets. What we see on the ground does not match how the region is discussed abroad. Here is what is actually happening to the electrons.
The Generation Base Is Being Rebuilt at Speed
Türkiye added a record 6.5 GW of wind and solar capacity in 2025 alone, bringing its combined total to roughly 40 GW. Wind and solar together now outproduce hydropower in Türkiye for the first time. The 2035 target is 120 GW, a fourfold increase from today, backed by 80 billion dollars in planned investment. When we visited Turkish energy companies last year, these numbers came across as a baseline rather than an aspiration.
Türkiye end-2024; Greece 2026 expected; Romania end-2025; Bulgaria end-2024. Türkiye targets 120 GW of combined wind and solar by 2035.
Greece generated 74% of its electricity from renewables in the first quarter of 2025. It is on track to reach its 2030 solar target by 2026, four years early, having added a record 2.5 GW of new solar in 2024. Offshore wind legislation enacted in 2024 targets 2 GW by 2030 in the Aegean and Ionian Seas. Greek energy companies are consolidating in parallel: HelleniQ Energy acquired Elpedison and relaunched it as Enerwave, targeting 12% market share and doubling installed capacity to 2.6 GW, while Heron merged with NRG to form the country’s third-largest electricity provider with 550,000 customers.
Romania added 2.2 GW of solar in 2025, a third consecutive record year, taking cumulative capacity past 7 GW, with utility-scale installations almost doubling year on year. Its CfD auctions have awarded 4.2 GW of renewable capacity. Renewables accounted for 48% of Romania’s electricity generation in 2024.
Bulgaria reached 4.57 GW of cumulative solar by the end of 2024, adding 1.28 GW in that year alone. In 2025, for the first time, the Electricity System Operator reported to ENTSO-E that renewables collectively became the second largest source of Bulgarian electricity after nuclear, overtaking coal, while coal-fired generation fell to a historic minimum.
These are commissioned assets, signed contracts, and operational capacity rather than ministerial ambitions.
Storage Is the Structural Advantage
Bulgaria’s battery energy storage pipeline now stands at 14 GWh, with 15 GWh expected by mid-2026. The RESTORE program, backed by EU Recovery and Resilience funds, initially targeted 3 GWh of standalone storage. The first auction alone allocated nearly 10 GWh across 82 projects with up to EUR 600 million in public support. A second round added more than 4 GWh across 31 projects.
Bulgaria has more than four times Germany’s grid-scale battery capacity, on one forty-second of the economy. Germany grid-scale figure end-2025 (Fraunhofer ISE); its 25 GWh national total is roughly 80% residential home storage. Bulgaria mid-2026 expected, almost entirely utility-scale. GDP figures 2025.
The comparison deserves a moment. Germany’s national battery total of roughly 25 GWh is about 80% residential home storage. Its grid-scale fleet stood at 3.7 GWh at the end of 2025. Bulgaria’s buildout is almost entirely utility-scale, standalone or co-located with generation, and directly available to the transmission system.
One project illustrates the pace. ContourGlobal’s 500 MWh battery facility, commissioned in January 2026, was built inside the fence of the Maritsa East 3 coal plant in seven months. Coal infrastructure repurposed for grid-scale storage inside a single year.
The Terrain Advantage That Remains Unnoticed
Southeast Europe’s mountainous geography has always been treated as an infrastructure liability, which is why roads, railways, and pipelines cost more per kilometer in the Balkans than on the North European Plain. In the context of the energy transition, that same terrain becomes an asset.
Pumped-storage hydropower is the most mature, longest-duration form of grid-scale energy storage available. It requires exactly what the Balkans have in abundance: elevation differentials, narrow valleys, existing river systems, and reservoir infrastructure.
Bulgaria learned the cost of neglecting it the hard way. Chaira, the largest pumped-storage facility in Southeast Europe at 864 MW, went completely offline in mid-2022 after a series of crashes following a botched rehabilitation. For nearly three years, Bulgaria’s single most important storage asset produced nothing, through the worst energy crisis in European memory. The country could not store cheap surplus electricity for peak demand, nor provide the flexibility a growing solar fleet requires. Unit 2 returned in late 2024, described by the energy minister as a historic moment. Unit 3 followed. Toshiba, the original manufacturer, has been contracted to repair unit 1, with units 1 and 4 requiring full turbine replacement at a cost of EUR 102 million. Chaira is coming back, and the government has identified ten further sites for new pumped-storage projects, alongside planned facilities at the Batak and Dospat dams. NEK has also completed the rehabilitation of the Belmeken pumped-storage plant, rated at 373.5 MW, in the same cascade.
A 600 MW reversible pumped hydro project is under development on the Drina River in Bosnia’s Republic of Srpska. Greece has Gkioufa, a 700 MW project, in its pipeline.
Batteries handle hours. Pumped hydro handles days and seasons. A region building 15 GWh of battery storage while sitting on some of Europe’s best pumped hydro topography has a storage portfolio that most of Western Europe cannot replicate without building from scratch.
Two Green Corridors for Caspian Electrons
The buildout does not stop at the region’s borders. Two parallel routes are being developed to bring Caspian renewable power into Europe, and Bulgaria participates in both.
The northern route is the Caspian-Black Sea-Europe Green Energy Corridor: a 1,195 km HVDC submarine cable from Georgia to Romania, operated by GECO, a joint venture of four national transmission operators, Azerenerji, Georgian State Electrosystem, Transelectrica and MVM. Bulgarian Energy Holding took a 20% stake in 2024. Initial capacity is 1.3 GW, scaling toward 4 GW, with the first cable targeted around 2032.
In July 2026, the twelfth ministerial steering committee in Baku confirmed that the CESI feasibility study was complete and that the project had formally advanced from planning into development. GECO is now preparing the roadmap to the Final Investment Decision. The World Bank Group, EBRD and Asian Development Bank are all engaged. Participants signed a joint letter to the European Commissioner for Energy backing inclusion in the EU’s third list of Projects of Mutual Interest, and the next ministerial meeting is scheduled for Romania in November. Bulgaria and Italy both attended in Baku – Italy, because the corridor’s ultimate market reach extends to the Apennine peninsula.
The southern route is AGTB, connecting Azerbaijan, Georgia, Türkiye and Bulgaria overland, initiated by Presidents Radev and Aliyev in 2024. At Baku Energy Week in June 2026, Bulgaria and Azerbaijan confirmed the next steps: an intergovernmental agreement between all four states along the route, a detailed roadmap, and a pre-feasibility study beginning this year. The route builds on the existing East-West electricity corridor already constructed by the Turkish and Bulgarian transmission operators, which connects the Balkan peninsula to the Apennine.
Southeast Europe is being physically wired as the junction between Caspian supply and European demand.
The Coal Transition, Messy but Real
No honest account of the region can skip coal. Bulgaria’s Maritsa basin hosts three major plants on three different trajectories. AES plans to end coal use at Maritsa East 1 by 2027. ContourGlobal is repurposing Maritsa East 3 into renewables and storage, with units 1 and 2 decommissioned, the 500 MWh battery operational and solar being added, although the plant was briefly restarted in January 2026 to preserve system security. State-owned Maritsa East 2, the largest coal plant in Southeast Europe at 1.6 GW, has pushed its phase-out to 2038.
The timelines are uneven. The direction is consistent, and the conversion of a coal site into a functioning storage facility in seven months compares favorably with most planned phase-outs in Western Europe.
The Demand Side, Where Compute Follows Electricity
The argument so far has been about supply. The demand side is where it becomes commercially concrete.
Europe’s established data center hubs have run into a physical wall. Amsterdam added no new capacity in 2024 under local moratoriums. Dublin’s development pause runs through 2028. Across the continent, 76% of operators name power availability as their single largest constraint. The European data center and AI infrastructure market is projected to roughly double from 47 billion dollars in 2024 to 114 billion by 2030, and that capacity has to be sited somewhere with electricity to spare.
That is now Southeast Europe. Croatia’s Project Pantheon, an AI campus near Zagreb, would be the highest-capacity facility in the EU and represents the largest private US investment in Europe. Romania is developing an 800 MW AI-focused complex and has submitted a Black Sea AI Gigafactory proposal to the European Commission. Greece’s Karatzis Group committed 278 million dollars to a data center campus in Boeotia in March 2026, and the Greek market is forecast to grow at over 10% annually through 2031.
The most instructive project is PPC’s. Greece’s Public Power Corporation has a EUR 5 billion data center plan sited in its depleted lignite mines in Western Macedonia, powered by 1.3 GW of photovoltaics, 300 MW of batteries, and two pumped-storage plants of 320 MW and 240 MW. Construction could begin in 2026 with completion in 2028, and phase two could reach 1 GW of data center capacity. A former coal region becomes a compute region, using its own grid connections, its own land, and its own new generation, with the utility positioned at both ends of the value chain.
This is what the region’s energy position converts into economically. Cheap power, available grid headroom, EU regulatory perimeter, and construction costs a fraction of the German equivalent. Compute follows electricity, and the electricity is here.
What Could Go Wrong
Any honest account of this region has to state the counterweights, because they are substantial and they are the reason the opportunity is still available.
Grid capacity is the first and most immediate. The interconnection between Balkan systems is thinner than the ambition requires, connection queues are long, and permitting quality varies sharply between neighboring countries. Capacity that cannot be evacuated is capacity that does not earn.
The underlying balance is also tighter than the generation figures imply. Bulgaria remains a net electricity exporter, but net exports fell to 1,268 GWh in 2025, roughly six times below 2022, because domestic coal and gas generation cannot compete against Turkish and North Macedonian output that carries no EU carbon cost. In individual periods, Bulgaria has flipped to net importer. A carbon cost that applies on one side of an interconnector and not the other quickly becomes a commercial problem.
Then there is operating discipline. Chaira sat idle for nearly three years through the worst price environment in European memory because a rehabilitation was mishandled. A storage portfolio only has value if it is available on the day the system needs it.
Governance risk is structural. Corruption remains endemic across much of Southeast Europe, and it is not incidental to the energy sector. Procurement, permitting, grid connection queues and state-owned utility management are precisely where it concentrates. Investors who assume EU membership guarantees EU-standard administration will be corrected quickly.
Political fragmentation is the last. Bulgaria, Greece, Romania and Croatia sit inside the EU and NATO. Türkiye is a NATO member outside the EU, with an independent foreign policy and its own energy diplomacy. Serbia is outside both, maintains close ties with Moscow, and has declined to sanction Russia. Bosnia and Herzegovina is internally divided on the question. A transmission corridor crossing four regulatory regimes and three security alignments is harder to finance than one that stays inside a single jurisdiction, and cross-border projects here carry political risk premiums that Northwest European projects do not.
None of this invalidates the case. It does mean the region rewards partners who understand the terrain rather than investors who arrive expecting Western European operating conditions.
What This Means for European Power Prices
The reason Western European power prices remain structurally high is not the lack of ambition. It is a shortage of a cheap, firm, well-sited supply. Northwest Europe is building expensive offshore wind into congested grids, with expensive labor, long permitting cycles, and limited storage topography. That is a genuine transition producing genuine results. It is also producing a cost base that the industry increasingly cannot absorb.
Southeast Europe is building the same transition on a different cost structure. High solar irradiation. Strong Black Sea and Aegean wind. Nuclear baseload is being renewed at Kozloduy, where Bulgaria expects to sign for two Westinghouse AP1000 units following a final investment decision. Mountain topography that makes pumped storage viable at a cost the North European Plain cannot match. Construction and labor costs are a fraction of those in Germany. And EU cohesion and recovery funding already deployed rather than promised: 15 GWh of Bulgarian battery capacity is under construction now, not scheduled for 2035.
The corridor function sits on top of all of it. When regional hydro ran dry, and Ukraine needed up to 2.1 GW of imports, Greece was exporting to five countries simultaneously. This region is where the European system finds its margin.
For industrial and digital investors, the implication is direct. The reshoring conversation keeps reducing the debate to two options: pay Northwest European power prices or leave the continent. There is a third option, three hours by plane from Frankfurt, within the single market and the EU carbon regime, with power and construction costs that look nothing like those in Germany. The data center developers have already found it. Heavy industry will follow.
Southeast Europe is not waiting to become relevant to European energy. It already is. The open question is whether the rest of the continent engages in time to invest, partner and build here, or discovers it once the capacity is spoken for.
