By 2025 South-East Europe’s electricity market has turned into a dense web of cross-border flows where almost every country is simultaneously an importer and an exporter, often within the same day. Annual balances, hourly flows and price patterns show a region that is no longer a peripheral appendage to the core EU market but an increasingly integrated, sometimes volatile, trading zone. Volumes and prices vary significantly by country, but the structural picture is clear: Slovenia, Croatia and Hungary act as key gateways for Central Europe, Romania and Bulgaria anchor the eastern side with strong generation bases, and the Western Balkans—Serbia, Bosnia and Herzegovina, Montenegro, Albania, North Macedonia—along with Greece, balance between domestic constraints and regional opportunities.
Slovenia operates as a high-transit, structurally import-leaning market. With annual consumption in the 14–15 TWh range and modest domestic generation dominated by Krško nuclear, hydro and some thermal and renewables, Slovenia imports a significant share of its needs while simultaneously exporting when Krško and hydro output are strong. Net imports typically hover in low single-digit terawatt-hours over a year, but gross flows are much higher because Slovenia sits on important north–south and east–west corridors, linking Italy and Austria with Croatia and Hungary. Prices largely follow the Central European pattern, frequently close to the German–Austrian and Hungarian day-ahead benchmarks, with 2025 average day-ahead prices in the 70–90 euro per MWh band depending on month and hydro conditions. Slovenia’s trading volumes are therefore not just about covering domestic demand; they also reflect its role as a transit market and balancing point between Italian price dynamics and Eastern European flows.
Croatia’s trading position is closely tied to hydro variability. Annual consumption is on the order of 17–18 TWh, with domestic production fluctuating between 11 and 15 TWh depending on water inflows and growing wind and solar contributions. In strong hydro years Croatia’s imports shrink and exports can briefly appear in the annual stats, but structurally the country remains a net importer, often in the 3–6 TWh range. Its main import partners are Slovenia and Hungary, while it can export into Bosnia and Herzegovina and, indirectly, toward the Western Balkans when conditions permit. Price levels for 2025 roughly track the wider SEE day-ahead averages: around 75–85 euros per MWh over the year, with deep dips in hours of strong regional renewables and spikes in dry, cold periods when hydro is constrained and regional gas and coal plants set the marginal price. Croatia’s position has improved somewhat with the build-out of LNG and greater flexibility in regional gas supply, but its electricity trade balance still reflects its status as a hydro-lean, import-reliant system in bad water years.
Hungary is a structurally import-dependent industrial market and a key price-setting hub for the region. Annual consumption is above 45 TWh, while domestic generation falls short by a substantial margin, leaving net imports often in the 10–14 TWh range. Hungary imports heavily from Slovakia, Romania and Croatia, while also acting as a transit route for flows between the Western Balkans and Central Europe. Paks nuclear anchors domestic baseload, but Hungary still relies on gas-fired generation and imports to meet peak and industrial demand. As a result, Hungarian day-ahead prices are closely watched across the region; in 2025 they typically sit near or slightly above core EU levels, often in the 80–90 euros per MWh range on average, with pronounced volatility when gas prices move or when regional renewables deviate from forecast. For Serbia, Romania and Croatia, Hungary’s price is a primary reference because it reflects the intersection of Central European supply and South-East European demand.
Serbia has, by 2025, re-established itself as a net exporter of electricity in an average hydrological year, though the balance remains sensitive to water levels and coal plant performance. Annual consumption in Serbia has settled around 33–34 TWh, and EPS’s generation, combining lignite, hydro and growing wind, typically exceeds this by 2–4 TWh when conditions are normal. After the acute crisis years when imports spiked and prices surged, 2024 and 2025 saw Serbia export in the low single-digit TWh range on an annual basis, primarily into Bosnia and Herzegovina, Montenegro, North Macedonia and, via interconnectors, into Hungary and Romania. Day-ahead prices on the Serbian power exchange have converged toward Hungarian and regional levels, with annual averages in the 70–85 euros per MWh zone, but Serbia’s export capability gives it a more favourable macro-energy profile than many neighbours. When hydrology is strong and coal plants are stable, EPS appears as a structural seller, using its comparatively low production costs to monetise exports. When hydrology weakens, Serbia’s balance can quickly swing to modest net imports, highlighting the underlying fragility of a system still dominated by lignite and rivers.
Romania operates as both a regional anchor exporter and a sometimes-importer depending on hydro and wind performance. With total consumption around 55–57 TWh and generation capacity spanning hydro, nuclear, gas, coal, wind and solar, Romania is among the most diversified systems in SEE. In a year of average hydrology and renewables, Romania can export 4–6 TWh net, mainly to Hungary and Bulgaria, but in dry or low-wind conditions, particularly in winter, it can swing into net import territory. The year 2025 reflects this pattern: strong renewables and reasonable hydro in spring and autumn produced substantial export surpluses, while cold spells with low wind saw short import spikes. Pricewise, Romania’s day-ahead levels generally track Hungarian and Bulgarian indices, ranging roughly between 70 and 90 euros per MWh over the year. Combined with nuclear baseload, these dynamics make Romania a key stabiliser in regional trading, particularly for Hungary and Bulgaria.
Bulgaria remains one of Europe’s more significant net exporters of electricity. With domestic generation between 40 and 45 TWh and internal demand closer to 30–32 TWh, Bulgaria regularly exports 10–12 TWh per year, mainly to Greece, Romania, North Macedonia and Serbia. Nuclear, coal and expanding solar fleets underpin this export capability. In 2025, despite gradually declining coal utilisation, Bulgaria’s net export position remains strong, although occasional domestic price spikes occur when regional systems are tight or when units are offline. Average day-ahead prices sit broadly in line with Romanian and Greek levels, but Bulgaria’s large export volumes and the presence of nuclear baseload give it a structurally favourable trade and price profile relative to its neighbours.
Bosnia and Herzegovina continues to be a net exporter, but with far more volatility than Bulgaria. Annual generation of around 17–18 TWh, dominated by hydro and coal, compares with domestic consumption of roughly 13–14 TWh, leaving a net export position of 3–4 TWh in good years. However, swings in hydrology and coal supply have produced dramatic financial and operational variations. In 2024–2025 some months saw Bosnia exporting aggressively into Croatia and Serbia, while others saw much tighter balances and reduced export volumes. Price levels in domestic contracts and cross-border deals reflect this instability; Bosnia can profit from high regional prices in tight systems, but it can also suffer when it must import in poor hydrological or technical conditions. Overall, Bosnia’s trade stats show a country with significant export potential but structurally exposed to weather and asset reliability.
Montenegro is a small but highly exposed system. With annual consumption of about 3.2–3.5 TWh, Montenegro’s domestic generation—hydro, the Pljevlja coal plant, and a growing wind and solar fleet—oscillates between 2 and 3 TWh depending on water and plant availability. As a result, net imports can range between 0.5 and 1.5 TWh per year. EPCG’s trading arm is active in regional markets, importing when domestic resources fall short and exporting when hydro and wind create surpluses, particularly at night. In 2024, for example, there were months where Montenegro was a net exporter in energy terms but still required imports for part of the year at high prices, particularly when Pljevlja was offline for environmental upgrades. Average price levels for Montenegro track the regional SEE hubs, but the impact on the national economy is more pronounced because of the small system size and the high share of imports in bad years.
Albania’s electricity trade is almost entirely driven by water. With domestic consumption around 7–8 TWh and generation up to 9 TWh in wet years but only 5–6 TWh in dry years, Albania can swing between being a net exporter and a heavy importer. Its hydropower-only system means that in rainy years it sells large surpluses to the region, often several terawatt-hours, while in drought years it must import similar volumes, sometimes at punishing prices. In 2025, with hydrological conditions closer to average after a weaker 2024, Albania’s import needs have moderated but not vanished; trade volumes remain large relative to system size, and price exposure remains high in low-inflow periods. Without significant diversification into wind and solar, this volatility in Albania’s trade stats will persist.
North Macedonia is structurally import-dependent. Annual consumption of around 8–9 TWh compares with domestic generation of 5–6 TWh in a typical year, leaving net imports of 2–4 TWh. Coal plants, gas units, hydro and new renewables temper this gap but do not close it. North Macedonia relies heavily on imports from Bulgaria, Serbia and Greece, often at prices that reflect regional scarcity. In 2025 rising wind and solar output have marginally reduced import needs, especially in shoulder seasons, but the country remains one of the more structurally import-dependent markets in SEE. Its price levels tend to track or slightly exceed regional averages, because its vulnerability to scarcity episodes raises risk premia in contracts.
Greece occupies an increasingly interesting dual role as both importer and exporter at different times of the day and year. With consumption around 50 TWh and a generation mix dominated by gas, renewables and some remaining lignite, Greece imports in some high-demand or low-renewable periods but exports heavily when solar and wind are strong. Net annual imports might still sit in the 2–4 TWh range, but gross flows are much larger. During sunny, windy midday hours Greece increasingly exports surplus power into Bulgaria, North Macedonia and Italy, depressing local prices and helping neighbours cover demand at lower cost. In evening and low-renewable hours it resumes its role as a net importer. Average prices in Greece are often at the upper end of the regional spectrum—80–95 euros per MWh—reflecting higher gas dependence, but large renewable additions are narrowing this gap.
When we zoom out to a regional view, the 2025 trading stats across these eleven countries show a clear structure. Bulgaria and, to a lesser extent, Romania and Bosnia and Herzegovina function as stable exporters. Serbia sits in a swing position, importing in bad years and exporting in normal ones. Slovenia and Croatia are mid-sized markets with modest domestic generation shortfalls that make them structurally dependent on imports but also active traders. Hungary and Greece are large anchors whose price signals and supply-demand imbalances send ripples across the region. Montenegro, Albania and North Macedonia are small but highly sensitive systems whose import dependence or hydro volatility amplifies any regional price swings.
Price formation increasingly reflects this web. The Western Balkan day-ahead prices follow the Hungarian, Bulgarian and Greek curves, measurably depressed in hours when regional hydro, wind and solar are high, and sharply elevated when they are low and gas plants set the marginal price. Average day-ahead prices across SEE in 2025 cluster in a broad 70–90 euros per MWh band, with outliers in extreme weather or system-stress events. Spreads between countries are narrowing as interconnection capacity expands and markets integrate, but structural differences remain: nuclear-heavy Bulgaria enjoys more stable price conditions; import-dependent Hungary and Greece feel gas price effects more; hydro-dominated Albania and Montenegro live with high volatility because of their resource profiles.
For investors, traders and policymakers, the implications of these trading statistics are straightforward. Countries with stable or growing export surpluses, underpinned by nuclear, hydro, wind and increasingly solar, enjoy stronger trade balances, better macro-risk profiles and more room to manage domestic tariffs and industrial pricing. Systems with structural import dependence, especially where this is tied to a narrow generation mix, carry higher exposure to external shocks and will need to accelerate diversification. Overall, South-East Europe in 2025 is no longer a quiet corner of the European power market. It is a dynamic, often volatile trading zone in its own right, where cross-border volumes and prices reflect a complex but increasingly integrated regional energy economy.