State-owned power utilities in South-East Europe remain the structural backbone of the regional electricity system, even as private renewables, batteries and merchant assets dominate new capacity additions. What has changed is not their centrality, but the nature of their financial exposure. Today, state utilities sit at the convergence of legacy megawatts, new grid investments, lender-driven capital programmes and mounting long-term liabilities linked to security of supply, decarbonisation and price stabilisation. To understand their role, it is necessary to look simultaneously at installed capacity, financed projects, balance-sheet exposure and lender behaviour.
Across SEE, utilities such as Elektroprivreda Srbije, Elektroprivreda Crne Gore, Hrvatska elektroprivreda, Elektroprivreda Bosne i Hercegovine, Elektroprivreda Republike Srpske, Bulgarian Energy Holding and their Romanian and Greek counterparts collectively control more than 70 GW of installed generation capacity, dominated by coal and lignite at roughly 40–45 %, large hydro at 25–30 %, gas at 10–15 %, and renewables excluding hydro still below 15 %. This legacy fleet underpins system adequacy, but it also anchors a massive capital and environmental burden.
The financial scale attached to these megawatts is substantial. Annual revenues of the largest SEE state utilities range between €1.5 billion and €5 billion per company in normal price years, while balance-sheet debt typically ranges from €500 million to over €3 billion. When aggregated across the region, state-owned utilities carry outstanding financial liabilities comfortably exceeding €20–25 billion, much of it linked to long-term loans from multilateral lenders and syndicated commercial facilities.
Lenders are deeply embedded in this structure. The most influential financiers remain the European Bank for Reconstruction and Development and the European Investment Bank, whose combined exposure to SEE power utilities and related grid operators runs into tens of billions of euros. These institutions finance projects that are often too large, too long-dated or too politically sensitive for pure commercial lending.
In Serbia, state-backed power projects financed over the past decade include thermal plant overhauls exceeding 1 500 MW, hydropower rehabilitation programmes covering more than 3 000 MW, and grid reinforcement investments above €1.2 billion. Individual EBRD and EIB loans to the Serbian power sector frequently fall in the €100–300 million range per facility, with maturities of 15–20 years. These loans typically fund environmental retrofits, ash-handling systems, flue-gas desulphurisation, dam safety upgrades and transmission expansion rather than new revenue-generating assets.
In Croatia, Hrvatska elektroprivreda has financed a portfolio of hydro upgrades, gas-fired capacity and grid modernisation with cumulative capital expenditure exceeding €2 billion over the past decade. Single projects, such as combined-cycle gas plants or major hydro refurbishments, often involve financing packages of €300–500 million, blending EIB loans, commercial bank tranches and state guarantees. Installed capacity under HEP management remains above 11 000 MW, but the average age of thermal assets exceeds 35 years, implying rising maintenance and replacement costs.
Bulgaria’s Bulgarian Energy Holding controls generation and grid assets exceeding 12 000 MW, including large coal complexes and nuclear capacity. Financing exposure is correspondingly large. Debt outstanding across BEH entities has exceeded €4 billion at various points, with lenders repeatedly refinancing legacy obligations while adding new loans for grid reinforcement and environmental compliance. Capital required for coal transition, nuclear life-extension and renewables integration is estimated in the €10–15 billion range over the next two decades.
Bosnia and Herzegovina’s state utilities collectively operate around 4 500 MW of installed capacity, heavily skewed toward coal and hydro. Financing has focused on hydropower rehabilitation projects of 200–500 MW in aggregate and environmental retrofits for coal plants. Typical loan sizes range from €50–150 million, but the relative burden on utility balance sheets is high given smaller revenue bases. Debt-to-equity ratios at entity utilities often exceed 60 %, limiting future borrowing capacity without state backing.
Montenegro’s Elektroprivreda Crne Gore, despite a smaller system of roughly 1 000 MW, has financed hydropower upgrades, wind integration and grid modernisation with cumulative investment exceeding €700 million over the past decade. Individual lender facilities of €50–100 million are material relative to annual revenues of €300–400 million, underscoring the sensitivity of smaller systems to financing shocks.
These financed projects illustrate a critical distinction. While private developers finance new wind, solar and battery assets with ring-fenced project finance, state utilities finance system assets: grids, legacy plants, environmental compliance and reserve capacity. These investments are capital-intensive but often generate limited incremental cash flow. Their economic justification lies in system stability, political mandates and long-term security of supply rather than pure return on capital.
The recent energy price crises exposed this asymmetry brutally. State utilities across SEE absorbed extraordinary losses to shield households and politically sensitive industry from price spikes. In several countries, annual losses exceeded €500 million in a single year. These deficits were covered through emergency credit lines, short-term bank loans, deferred payments to fuel suppliers and direct budget transfers. In effect, lenders and governments converted market volatility into public-sector liabilities.
Private renewables and batteries did not remove this burden. They reduced fuel exposure and imports, but they did not eliminate the need for firm capacity, reserves and grid stability. State utilities remain responsible for balancing the system when wind and solar underperform, for maintaining hydropower reservoirs, and for operating thermal units that run at low load factors but must remain available. These obligations translate into ongoing capital needs.
Looking forward, lenders estimate cumulative investment requirements for SEE state-owned power systems in the €30–50 billion range by 2040. This includes grid reinforcement for renewables integration, replacement of ageing coal capacity, environmental remediation, digitalisation and new flexibility assets. Much of this will be financed through debt, increasing leverage unless tariffs and market design change materially.
Lenders are adapting their approach accordingly. Multilateral banks increasingly condition new loans on governance reforms, tariff adjustments and decarbonisation pathways. Commercial banks shorten maturities and tighten covenants, even where sovereign backing is assumed. In contrast, private RES and battery projects increasingly enjoy higher leverage and more favourable risk allocation, because their liabilities are contractually ring-fenced.
This creates a structural divergence. Private investors capture upside from volatility and optimisation, while state utilities accumulate long-term liabilities tied to system adequacy and political obligations. Megawatts may increasingly be privately owned, but risk of last resort remains public.
For lenders, this duality defines strategy. They finance private assets for return and predictability, and state utilities for stability and systemic necessity. The two are inseparable. The bankability of private renewables depends on resilient state-owned grids and backup capacity, while the solvency of state utilities increasingly depends on private investment reducing fuel exposure and import dependence.
In South-East Europe, the energy transition is therefore not a clean transfer of assets from public to private hands. It is a reallocation of financial risk. State-owned utilities continue to carry the heaviest long-term liabilities, measured not only in debt but in political and social obligations. Lenders understand this reality. They price it, structure around it and, increasingly, attempt to limit it. But they cannot escape it.
The future of the SEE power system will be shaped not just by how many megawatts are financed, but by who carries the residual risk when markets fail. On current trajectories, that risk remains firmly anchored in state-owned utilities and, by extension, public balance sheets.
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