South-East Europe’s power transition is no longer being financed primarily through utility balance sheets and state-backed transmission plans. The ownership map is changing. Strategic developers, trading houses, sovereign-backed energy platforms, infrastructure-style lenders and multilateral institutions are now building a layered capital stack across the region, and that stack is increasingly determining which assets move first, which markets scale faster and which technologies capture the highest margins. The shift matters because the region’s power market is no longer a simple build-and-sell environment. It is becoming an investable infrastructure system where returns depend on who can fund congestion relief, hybridisation and route-to-market structures at speed. The EIB Group said it invested €822 million in the Western Balkans in 2025, mobilising about €1.5 billion of new investment, while the EBRD reported record annual investment of €955 million in Romania in 2025, with 81% directed to the green economy.
The financial scale of the regional transition explains why capital structure now sits at the centre of the story. Transmission upgrades across South-East Europe still imply a pipeline in the multi-billion-euro range through 2030, while renewable and storage additions require several times that amount again. Multilateral institutions are effectively acting as the first-loss and crowd-in layer for private capital rather than the sole funding source. The EBRD’s 2025–2030 Strategic and Capital Framework explicitly states that it will leverage public-sector and institutional interventions to mobilise private-sector capital and address project implementation risks in sectors including energy and telecoms. That matters because South-East Europe still offers double-digit equity cases in renewables and storage, but many projects remain too complex or too exposed to merchant volatility to clear on private capital alone without some risk compression at the front end.
Romania is currently the clearest laboratory for this model. In February 2026, the EBRD announced €34 million of financing for solar projects in Romania, structured in two distinct tranches: up to €28 million for a 61.9 MW merchant-exposed plant and up to €6 million for a 127.8 MW plant supported by a 15-year CfD. The merchant tranche was backed by a first-loss guarantee from the EU under InvestEU, while the EIB separately said its financing formed part of a broader €121 million package supporting three solar parks in Oltenia. The point is not just the volume of money. It is the structure. Private capital is willing to fund Romanian solar, including merchant exposure, but it increasingly wants risk segmented: contracted versus merchant, guaranteed versus unguaranteed, grid-ready versus grid-dependent. That is the hallmark of an infrastructure market maturing into risk-priced layers rather than a single undifferentiated development story.
That same Romanian market is also attracting strategic private developers, not just public lenders. The EBRD-backed financing discussed in late 2025 for Nofar Energy’s Romanian solar projects was framed explicitly around scaling investment in a country targeting more than 10 GW of renewable capacity by 2030. At the same time, MET Group has continued to expand its Romanian platform. Its original entry was a 52 MWp photovoltaic acquisition near Bucharest with expected output of around 82 GWh per year, and by 2025 company-linked reporting showed it was also assessing onshore wind opportunities, with Romania already forming part of a portfolio including solar and storage assets. This combination—merchant-ready solar, strategic developer entry and multilateral-backed debt—signals that Romania is no longer a pure frontier market. It is becoming a platform market where successive capital pools can build on top of one another.
Greece is evolving differently but just as quickly. There, private capital is not entering mainly through early-stage greenfield risk. It is entering through platform consolidation and scale acquisition. Masdar’s acquisition of Terna Energycreated a Balkan gateway that is now openly being used for broader regional expansion. Reporting in January 2026 said Masdar was scanning new acquisitions in Greece and the Balkans through the Terna platform, while Masdar’s own corporate material states that its global project portfolio capacity reached more than 51 GW. This is important because Masdar is not behaving like a single-project investor. It is behaving like a long-duration platform owner, seeking to accumulate operating and near-ready assets across interconnected markets where scale can be monetised through storage, route-to-market optimisation and eventually cross-border offtake structures.
Montenegro provides a particularly revealing example of how sovereign-backed strategic capital is moving into places where conventional private infrastructure investors might once have hesitated. In January 2026, reporting from both sector media and project-focused outlets showed Masdar and EPCG moving toward a joint venture aimed at large-scale renewable development in Montenegro, with a stated ambition to serve domestic demand and enable exports to the wider Balkans and southeast Europe using the existing Italy subsea link and possible future expansion. That is a structurally different proposition from a standard Balkan wind or solar park. It is effectively a platform built around sovereign alignment, export optionality and transmission leverage. In commercial terms, it moves Montenegro closer to being an Adriatic infrastructure node rather than a peripheral small market.
This is where private capital starts to behave less like traditional project finance and more like corridor finance. Investors are no longer looking only at the economics of a single plant. They are pricing access to a system: interconnectors, balancing markets, curtailment zones and industrial demand nodes. That is why traders such as MET Group are becoming more important owners rather than just counterparties. MET’s long-standing development in Serbia with NISaround a 102 MW wind park in Plandište is still one of the clearest examples of a trading-linked capital model expanding from market activity into owned generating exposure. Once a trader controls generation, storage and route-to-market in the same region, the return profile changes. Revenue is no longer only merchant. It becomes a blend of physical output, congestion insight and optimisation income.
Serbia is now moving toward the next phase of that story. The most telling signal in early 2026 was not a conventional utility tender but the EBRD’s due diligence and structured financing talks around Fortis Energy’s Sremska Mitrovica solar-plus-BESS project. That transaction matters because it indicates that Serbia is becoming financeable for hybrid assets, not only for standalone renewables. Once multilateral capital starts underwriting Serbian PV-plus-storage, the private market is likely to follow, because storage is the exact layer that turns weak merchant solar into stronger infrastructure-style cash flow in a congested system. In financial terms, a hybrid asset can move from the lower end of the regional return spectrum—roughly 7–9% equity IRR for a weaker solar case—toward 11–15% with the right storage sizing, route-to-market strategy and contracted floor. The availability of institutional debt at that point becomes decisive.
This capital migration is not random. It follows where risk can be segmented. Private capital in South-East Europe increasingly wants one of four structures. It wants regulated or quasi-regulated transmission and substation exposure with lower returns but higher predictability. It wants contracted renewables with investment-grade or quasi-investment-grade counterparties. It wants hybrid storage portfolios where volatility is deep enough to support optimisation returns. Or it wants strategic platforms where scale itself is the asset, allowing later refinancing or partial sell-down. The EBRD and EIB are repeatedly showing how those structures are being created in practice: guarantees for merchant solar, debt for CfD-backed assets, catalytic lending for regional energy security and green-economy investments at country level.
That also explains why pure frontier-style return expectations are starting to bifurcate. Regulated or transmission-adjacent assets still fit more traditional infrastructure return brackets, often around the high single digits on equity in stable structures. Contracted renewables generally sit higher. Battery and hybrid portfolios sit higher again because their revenues still depend on optimisation quality and regulatory evolution. What private capital likes about South-East Europe is not simply that returns are higher than in mature EU core markets. It is that the spread between asset classes is wide enough to support portfolio construction inside one region. A sponsor can hold a lower-risk renewable base in Romania, a higher-volatility battery position in Greece, and a development option in Serbia or Montenegro, all while using one regional operating logic tied to grid bottlenecks and cross-border pricing. The region has become portfolio-diversifiable in a way it was not ten years ago.
Battery storage is central to this. The 2026 market assessments for South-East Europe increasingly point to Bulgaria and Romania as some of the faster-moving storage stories in the region, while Greece remains the leading volatility market. That combination is attractive to infrastructure-style investors because storage is one of the few assets that can monetise both the current system and the transition to the next one. In today’s market, batteries capture intraday spreads, balancing payments and renewable shaping value. In a more mature market, they become the enabling layer for higher renewable penetration and firmer industrial offtake. Capital likes that because it creates two valuation narratives: current yield and future strategic indispensability.
The rise of digital infrastructure adds another dimension. Infrastructure funds that previously looked at energy, telecoms and data centres as separate silos are beginning to see them as one integrated system. Greece’s IPTO–Serverfarm data-centre venture and Romania’s 800 MW ClusterPower-linked data-centre build-out make that especially clear. Once large digital load arrives, private capital can justify renewable clusters, BESS, transmission reinforcement and long-term structured supply around a single anchor demand story. In that context, energy is no longer just an infrastructure sub-sector. It becomes the enabling capex behind a wider digital economy build-out. This is one reason why infrastructure investors with mandates spanning both power and telecoms are likely to become more influential in the region through 2030.
The ownership model is also changing in another important way: strategic investors are increasingly entering before the fully de-risked stage. In older SEE renewables cycles, capital often waited for feed-in support, full permitting clarity or late-stage development packages. Now, because the best congestion-adjacent nodes, hybrid-ready sites and large-load opportunities are finite, some investors are moving earlier. That is visible in MET’s Romanian renewables expansion and Masdar’s Balkan acquisition posture. It is also visible in the willingness of multilaterals to use guarantees and blended structures to bring merchant projects to bankability earlier than the market would once have tolerated.
For sponsors, this creates both opportunity and pressure. The opportunity is obvious: more capital sources, more refinancing routes, more strategic buyers and more appetite for portfolios rather than one-off assets. The pressure is that capital is becoming more selective, not less. Projects without clear grid logic, storage strategy or credible offtake increasingly look incomplete. Private capital is not flooding indiscriminately into South-East Europe. It is clustering around investable structures. That means a 100 MW solar plant in a congested weak-demand node with no hybridisation may struggle to attract attractive capital terms even if the headline resource is strong. A 100 MW solar-plus-BESS project near an industrial or data-centre load, by contrast, can become far more financeable because its revenue stack is structurally deeper.
This is why Electricity.Trade matters beyond pure market commentary. In a capital market that is increasingly pricing assets by node, spread, flexibility and offtake quality, information becomes part of bankability. Investors want to know not only where the cheapest megawatt can be built, but where a megawatt can become an infrastructure-style cash flow. That requires visibility into congestion, intraday spreads, balancing value, storage monetisation and emerging demand centres. A regional intelligence layer is no longer auxiliary to private capital. It is part of how capital is deployed.
What is emerging, then, is a new ownership system for South-East Europe’s power market. Utilities are still present. States still matter, particularly in grids and policy. But the decisive growth capital is increasingly being provided by a mix of strategic renewables platforms, trader-backed portfolios, sovereign-linked energy investors and multilateral-supported infrastructure financing. The region’s energy transition will still be measured in megawatts and billions of euros. But the real competitive edge will lie in who can assemble the right capital stack around the right physical nodes. In South-East Europe, infrastructure value is no longer sitting only in wires and plants. It is sitting in the ability to own volatility, shape demand and finance optionality at scale.
