Hydropower is still the quiet balance-sheet engine of the South-East European power system. While wind and solar dominate headlines, it is the big river cascades, mountain reservoirs and ageing dams that decide whether utilities report record profits or scramble for imports at thin margins. Across Serbia, Montenegro, Bosnia and Herzegovina, Albania, North Macedonia, Croatia, Romania, Bulgaria and Greece, hydro output in 2023 and 2024 hovered around an estimated seventy terawatt-hours per year, depending on rainfall, snowmelt and reservoir management. That volume is concentrated in a relatively small number of large utilities and a handful of national river basins, which makes hydrology a first-order economic variable for the entire region.
Serbia’s EPS is one of the clearest illustrations of this dynamic. After a drought-hit 2022, the hydro fleet rebounded strongly, generating 12.7 TWh in 2023, a 41.3 percent increase on the previous year and enough for hydro to cover 36.5 percent of EPS’s total generation. That pushed total EPS production in 2023 to a record 35.5 TWh and underpinned the swing from heavy losses to almost a billion euros of net profit. When hydrology turned less generous in 2024 and total EPS output slipped to 32.9 TWh, the corporate result normalised, and Serbia’s imports rose by about 15 percent. One plant symbolises how important this resource is: the 1,140 MW Djerdap 1 hydropower station on the Danube exceeded its full-year 2024 production target by early December, already producing 5.42 TWh by 1 December. That volume from a single hydro complex is roughly equivalent to a third of Montenegro’s entire annual electricity production in a normal year, and the gross margin on those megawatt-hours is what finances much of EPS’s CAPEX and cushions volatile coal and import costs.
Montenegro’s EPCG has lived the same story in miniature. In 2023 its plants generated 3.50 TWh, of which large hydropower accounted for about 56 percent and the remainder came mainly from the Pljevlja coal plant. That year was wet and profitable. In 2024 the picture flipped: HPP Perućica produced 855 GWh, meeting 93 percent of its plan, and HPP Piva delivered 746 GWh, almost exactly on target, but an unprecedented drought across the wider system cut overall hydro volumes and forced EPCG to cover demand with higher-cost imports. Primary electricity production in Montenegro fell to 2.1 TWh in 2024 while imports surged to 5.95 TWh, only partly offset by exports of 6.11 TWh routed through trading operations. The result was a collapse in net profit from more than fifty million euros in 2023 to barely ten million in 2024, and by mid-2025 the utility had slipped into a year-to-date loss. For investors looking at EPCG, the hydrological risk is not an academic issue; it is the single biggest driver of earnings volatility and a key consideration when assessing debt-service capacity and dividend potential.
Bosnia and Herzegovina looks, on paper, like a hydropower winner. In 2023 the transmission-connected fleet alone produced 6.20 TWh of hydroelectricity, accounting for 42 percent of the 14.9 TWh generated on the high-voltage grid, while total national generation including distribution-connected plants reached about 17.2 TWh, with hydro contributing roughly 6.8 TWh or 39 percent. That hydro share, combined with substantial lignite-based output, made Bosnia one of the largest net exporters of electricity in the Western Balkans and delivered export revenues of several hundred million euros in 2022 and 2023. But when hydrology turns, the earnings picture changes fast. In 2023, weaker inflows and coal supply problems pushed EPBiH into a record loss of around 169 million euros, despite solid average prices. By contrast, in May 2025 favourable water conditions saw renewable generation, led by hydro, jump 75 percent year-on-year. This oscillation between under-performance and windfall illustrates why investors demand higher return premia for Bosnian utilities: hydro reserves are huge, but cash flows are hostage to rainfall.
Further south and west, hydro is even more dominant in Albania, which is effectively Europe’s only large pure-play hydropower system. In 2023, hydro plants generated 8.5–8.7 TWh, around 98 percent of total domestic electricity output. That made Albania almost completely dependent on water flows both for domestic supply and for its export/import balance. In 2024, hydro output fell back to 7.33 TWh, a drop of 16 percent that immediately tightened the country’s import needs and reduced the scope for export revenues. Investment figures tell the same story: clean-energy investment, predominantly in hydro and solar, dropped from about $204 million in 2023 to $117 million in 2024, a 43 percent fall that underlines the fragility of financing pipelines in systems that lack fuel diversification. For any lender or equity investor considering an Albanian project, scenario modelling around hydrology is essentially the core of the risk analysis.
Croatia, Romania and Bulgaria demonstrate how hydro interacts with broader, more diversified generation fleets. HEP’s Croatian system produced 15.1 TWh in 2023, about 2.7 TWh more than in 2022, largely thanks to stronger hydrology; hydro plants provided the majority of that volume, pushing the country close to a net-neutral position in electricity trade despite typically being an importer. In Romania, hydropower is structurally larger: the IEA estimates that hydro accounted for 32 percent of national electricity generation in 2023, while Hidroelectrica alone generated about 17.3 TWh that year before output fell to 13.9 TWh in 2024 when reservoir levels and inflows weakened. The swing of 3.4 TWh in net hydro production in a single year had macro implications: Romania produced 8.3 percent less electricity in the first ten months of 2024 compared with the same period a year earlier and briefly became a net importer. Bulgaria’s hydropower output is smaller in absolute terms but still material. Hydropower generation in 2023 is estimated at roughly 4.5–4.6 TWh, equivalent to about half of the 18 percent of Bulgarian electricity that came from renewables that year, and part of a broader clean-energy mix where nuclear accounts for 43 percent and fossil plants 29 percent of the 35.9 TWh produced. For these three systems, hydro is less existential than in Albania or Montenegro, but it remains a core driver of annual EBITDA and a crucial complement to nuclear, coal and gas.
North Macedonia and Greece occupy an intermediate position. North Macedonia’s installed hydro capacity in 2023 totalled 587 MW in ten large plants plus 133 MW in small hydropower, and those facilities typically generate around 1.1 TWh per year, about 15 percent of domestic consumption. Those volumes are modest in regional terms, but they form the main flexible resource in a system otherwise dominated by two coal plants totalling 824 MW and a small gas CHP fleet. Greece, meanwhile, has rapidly expanded wind and solar, but hydro still sits in the background as an important yet not dominant player. Total green electricity, including wind, solar and hydro, reached 21.35 TWh in 2023, a decade high, while combined gas and lignite generation fell to 19.2 TWh, the lowest level since the 1970s. Hydro is a minority share of that green total, but it remains critical for peak management and for filling gaps when wind and solar output dips.
The economic logic behind hydropower in South-East Europe is fairly consistent across countries. Once the capital expenditure is sunk — for dams, reservoirs, turbines and transmission lines — the marginal operating costs of hydro generation are very low. OPEX is dominated by staff, routine maintenance and periodic turbine overhauls, not by fuel. In Serbia, for example, the levelised OPEX of Djerdap 1 is a fraction of the fuel and CO₂ cost per megawatt-hour at a lignite plant. The same holds for Albania’s Drin cascade or Montenegro’s Piva and Perućica plants. This means that in wet years, when plants can run at high capacity factors, the incremental cash margins are extremely high and rapidly bulk up EBITDA. In dry years, by contrast, utilities face a double squeeze: they lose this high-margin output and must either ramp up costlier coal and gas or import electricity at market prices, pushing up system-wide OPEX and often wiping out profits.
CAPEX is now moving to reflect this reality. Most major utilities in the region are budgeting multi-hundred-million or billion-euro programmes to rehabilitate and uprate their hydro fleets. EPS has a hydro refurbishment programme of more than €1.3–1.5 billion through 2030, including new runners, generator rewinds and control systems that can add 10–15 percent to plant capacity and extend operational life by several decades. Hidroelectrica is investing roughly RON 3 billion (about €600 million) in refurbishment projects to 2034, while further projects are in the pipeline. North Macedonia has lined up loans of almost €100 million for modernising six major hydropower plants that together generate 1.1 TWh annually, precisely because they are seen as critical balancing assets in a system that must gradually retire coal. For investors, these CAPEX plans are attractive not only because they target assets with proven performance and high utilisation, but also because they are usually structured with long tenors, low interest rates and, increasingly, climate-linked grant components.
Looking at the region as a whole, hydropower in South-East Europe is carrying four simultaneous roles. It is a baseload contributor in some systems, a flexible balancing resource in others, an earnings amplifier in high-water years and an anchor for green CAPEX programmes supported by European institutions. It underwrites credit metrics for some utilities and exposes others to volatility when rainfall fails. For industrial consumers, the performance of these hydro fleets affects wholesale price levels and therefore long-term power purchase costs. For states and lenders, hydropower rehabilitation projects are among the most bankable transition investments available: they extend the life of low-carbon assets, improve system reliability and provide some of the cheapest megawatt-hours in the regional stack.
The strategic conclusion is that hydropower remains the core physical and financial hedge of the SEE power system. As wind and solar deployment ramps up and coal is gradually squeezed, the value of flexible, dispatchable, low-OPEX hydro will rise further. For investors and policymakers, understanding the hydrology of the Drina, Danube, Drin and Vardar rivers is not a technical curiosity; it is a prerequisite for forecasting earnings, evaluating CAPEX returns and assessing macro-energy risks in South-East Europe.