By 2025, South-East Europe’s power market has developed into a network of cross-border trades in which most countries act as both importers and exporters, sometimes within the same day. Annual balances, hourly flows and price patterns show a region that is increasingly integrated with wider European trading while remaining prone to volatility. The structural map highlights Slovenia, Croatia and Hungary as key gateways for Central Europe and Romania and Bulgaria as eastern anchors with large generation bases. The Western Balkans—Serbia, Bosnia and Herzegovina, Montenegro, Albania and North Macedonia—together with Greece sit across domestic constraints and regional opportunities.
Central gateway markets: Slovenia and Croatia
Slovenia records annual consumption in the 14–15 TWh range alongside modest domestic generation led by Krško nuclear, hydro, thermal output and renewables. The market imports a significant share of its needs while exporting during periods when Krško and hydro production are strong. Net imports typically remain in low single-digit terawatt-hours over the year, but gross cross-border flows are much higher due to Slovenia’s role on north–south and east–west corridors linking Italy and Austria with Croatia and Hungary. In 2025, average day-ahead prices generally fall within 70–90 euros per MWh, tracking Central European benchmarks.
Croatia’s trading position is closely linked to hydro variability. Annual consumption is around 17–18 TWh, while domestic production fluctuates between 11 and 15 TWh depending on water inflows and the expansion of wind and solar. In years with strong hydro conditions, imports fall and exports can appear in annual figures, but Croatia remains structurally a net importer, often in the 3–6 TWh range. Its main import partners are Slovenia and Hungary, while exports can flow into Bosnia and Herzegovina and indirectly toward the Western Balkans when conditions allow.
For 2025, Croatia’s day-ahead prices broadly follow wider SEE averages at about 75–85 euros per MWh over the year. Prices tend to dip during hours when regional renewables are strong and rise in dry, cold periods when hydro is constrained and regional gas and coal units set marginal prices. The country’s position has improved with LNG build-out and increased flexibility in regional gas supply. Even so, Croatia’s electricity trade balance continues to reflect its hydro-lean profile in low-water years.
Price-setting hub: Hungary’s import dependence
Hungary operates as a structurally import-dependent industrial market with consumption above 45 TWh. Domestic generation falls short by a substantial margin, leaving net imports typically in the 10–14 TWh range. Imports come heavily from Slovakia, Romania and Croatia, while Hungary also functions as a transit route for flows between the Western Balkans and Central Europe. Although Paks nuclear supports baseload supply, Hungary still relies on gas-fired generation and imports to cover peak demand and industrial load.
Hungarian day-ahead prices are watched across the region because they reflect the intersection of Central European supply with South-East European demand. In 2025, prices typically sit near or slightly above core EU levels, often averaging 80–90 euros per MWh. Volatility increases when gas prices change or when regional renewables deviate from forecasts. For Serbia, Romania and Croatia, Hungary’s price is described as a primary reference point for market conditions.
Swing exporter: Serbia; diversified system: Romania; exporter base: Bulgaria
Serbia returned to net exporting by 2025 under average hydrological conditions, though outcomes remain sensitive to water levels and coal plant performance. Consumption is around 33–34 TWh, while EPS generation combining lignite, hydro and growing wind typically exceeds demand by 2–4 TWh. After earlier crisis years when imports spiked, 2024 and 2025 saw exports in the low single-digit terawatt-hours annually. Shipments went primarily to Bosnia and Herzegovina, Montenegro and North Macedonia, with additional deliveries into Hungary and Romania via interconnectors.
Serbian day-ahead prices on its power exchange have converged toward Hungarian and regional levels, with annual averages in the 70–85 euros per MWh band. When hydrology is strong and coal plants perform steadily, EPS acts as a structural seller using comparatively low production costs to monetize exports. If water conditions weaken, Serbia’s balance can shift quickly toward modest net imports. The described sensitivity is tied to a system still dominated by lignite generation and river inflows.
Romania functions as both an exporter anchor and a sometimes-importer depending on hydro and wind performance. Total consumption is about 55–57 TWh, supported by generation spanning hydro, nuclear, gas, coal, wind and solar. In an average year for hydrology and renewables, Romania can export 4–6 TWh net, mainly to Hungary and Bulgaria. Under dry or low-wind conditions—particularly in winter—the system can move into net import territory.
The 2025 pattern reflects stronger renewables plus reasonable hydro output in spring and autumn alongside short import spikes during cold spells with low wind. Day-ahead price levels generally track Hungarian and Bulgarian indices across the year at roughly 70–90 euros per MWh. With nuclear baseload included in supply mixes, these swings make Romania a key trading stabiliser for Hungary and Bulgaria. Bulgaria remains one of Europe’s larger net exporters of electricity with domestic generation between 40–45 TWh.
Bulgaria’s internal demand is closer to 30–32 TWh, supporting regular exports of about 10–12 TWh per year. Main destinations include Greece, Romania, North Macedonia and Serbia. Nuclear output alongside coal generation and expanding solar capacity underpins export capability. In 2025, despite declining coal utilisation over time, Bulgaria’s net export position stays strong while domestic price spikes occur occasionally when regional systems tighten or units are offline.
Balkan variability: Bosnia & Herzegovina; Montenegro; Albania; North Macedonia; Greece
Bosnia and Herzegovina continues as a net exporter but with higher volatility than Bulgaria. Annual generation is around 17–18 TWh, dominated by hydro and coal, compared with domestic consumption of roughly 13–14 TWh. This leaves a net export position of about 3–4 TWh in good years. Hydrology swings together with coal supply changes have produced large operational differences across months in 2024–2025.
The described period includes months when Bosnia exported aggressively into Croatia and Serbia alongside other months with tighter balances that reduced export volumes. Price levels in domestic contracts and cross-border deals reflect this instability because high regional prices can coincide with tight system conditions while poor hydrological or technical circumstances can force imports. Montenegro is characterised as a small but highly exposed system with annual consumption of about 3.2–3.5 TWh. Domestic generation—hydro plus the Pljevlja coal plant, along with growing wind and solar—oscillates between 2 and 3 TWh.
This leads to net imports ranging from about 0.5 to 1.5 TWh per year. EPCG’s trading arm participates actively by importing when resources fall short domestically and exporting when hydro or wind creates surpluses, particularly at night. In 2024 there were months where Montenegro was a net exporter in energy terms but still required imports at high prices during periods when Pljevlja was offline for environmental upgrades. Average price levels track regional SEE hubs but have greater national impact due to small system size.
Albania’s electricity trade depends almost entirely on water conditions. Consumption is around 7–8 TWh, while generation reaches up to 9 TWh in wet years but falls to only 5–6 TWh in dry years. The country can swing between being a net exporter—selling large surpluses often several terawatt-hours—and being a heavy importer when drought reduces output. In 2025 after weaker 2024 conditions described as closer to average, Albania’s import needs moderated but did not disappear.
The trade volumes remain large relative to system size while price exposure stays high during low-inflow periods because diversification into wind or solar is not described as significant enough to change that profile materially for the period discussed. North Macedonia is structurally import-dependent with consumption around 8–9 TWh. Domestic generation typically sits at 5–6 TWh, leaving net imports of about 2–4 TWh. Coal plants, gas units, hydro and new renewables reduce the gap but do not close it.
The country relies heavily on imports from Bulgaria, Serbia and Greece at prices reflecting regional scarcity episodes. In 2025 rising wind and solar output marginally reduced import needs especially during shoulder seasons; however North Macedonia remains among the more structurally import-dependent markets in SEE. Its price levels tend to track or slightly exceed regional averages due to vulnerability during scarcity events that raises risk premia in contracts.
A dual role market: Greece within daily cross-border trading patterns
Greece plays both an importing role during some periods of high demand or low renewables output and an exporting role when solar and wind are strong. Consumption is around 50 TWh, while generation is dominated by gas alongside renewables plus some remaining lignite capacity. Net annual imports may remain within the 2–4 TWh range even though gross flows are much larger due to intraday trading patterns.
The described pattern includes sunny midday hours when Greece increasingly exports surplus power into Bulgaria, North Macedonia and Italy while depressing local prices there relative to those exports’ timing effects on neighbours’ demand coverage at lower cost levels. During evening hours or periods of low renewable output Greece resumes its role as a net importer. Average Greek day-ahead prices are often at the upper end of the regional spectrum at about 80–95 euros per MWh, reflecting higher gas dependence even as renewable additions narrow that gap.
Regional pricing links across SEE day-ahead markets in 2025
A broader view across eleven countries shows an identifiable structure for 2025 trading outcomes based on described balances rather than single-direction trade positions. Bulgaria functions as a stable exporter along with Romania and Bosnia & Herzegovina to a lesser extent according to the figures provided for good-year performance ranges. Serbia is positioned as a swing exporter that imports during bad years but exports during normal ones based on hydrology sensitivity described earlier.
The mid-sized markets Slovenia and Croatia are described as structurally dependent on imports due to modest domestic generation shortfalls while also remaining active traders through corridor flows referenced earlier for Slovenia’s transit role. Hungary together with Greece are described as large anchors whose supply-demand imbalances influence regional pricing signals used across borders for reference purposes described for Hungary specifically for Serbia, Romania and Croatia.
The smaller systems Montenegro, Albania and North Macedonia are characterised as highly sensitive because their import dependence or hydro volatility amplifies regional price swings described through their resource profiles rather than through changes in generation mix alone within the period discussed earlier for each country’s consumption range.
Marginal pricing drivers: renewables highs versus gas-set hours; SEE average price banding
The day-ahead price formation across Western Balkans markets follows Hungarian curves alongside Bulgarian indices where it is stated that these prices move measurably lower during hours when regional hydro plus wind plus solar output are high. Prices rise sharply during hours when those resources are low because gas plants set marginal prices according to the description provided for SEE pricing behaviour in 2025.
A cross-region clustering places average day-ahead prices across SEE within a broad band of about 70–90 euros per MWh, with outliers linked to extreme weather or system-stress events mentioned for that year’s distribution rather than specific dates or hours beyond those descriptors provided earlier.
Narrowing spreads amid expanding interconnection capacity; structural differences persist by fuel mix exposure
The description notes that spreads between countries have narrowed as interconnection capacity expands alongside market integration efforts referenced generally rather than tied to specific projects or commissioning dates within this text set.
Nuclear-heavy Bulgaria is described as enjoying more stable price conditions relative to others because its supply mix includes nuclear baseload referenced earlier alongside its export volumes.
Croatia and Slovenia are described through their import-reliant profiles tied to hydro constraints rather than through any separate fuel-mix claim beyond what was already stated.
Bulgaria and Romania are also referenced through their roles affecting neighbouring indices via day-ahead tracking relationships stated earlier.