The electricity market in South-East Europe is increasingly influenced by the dynamics of liquefied natural gas (LNG), which serves as a critical component in price formation across the region. As renewable energy sources expand, the marginal pricing—determined during peak demand periods—is predominantly set by gas-fired generation. This trend is notably evident in Greece and extends through interconnected markets in the Balkans.
Central to this framework is Greece’s LNG import infrastructure, particularly the Revithoussa terminal, which has a capacity of approximately 7 billion cubic meters (bcm) annually. The recent expansion of this facility, alongside the addition of the Alexandroupolis floating storage regasification unit (FSRU) with a capacity of 5.5 bcm per year, has significantly enhanced Greece’s ability to import LNG, establishing it as a pivotal regional gas hub.
Gas prices at these terminals are benchmarked against global LNG rates, which are affected by factors such as Asian demand and European storage levels. The cost of gas delivered into Greece translates into power generation expenses ranging from €70 to €120 per megawatt-hour (MWh), influenced by plant efficiency and carbon pricing under the EU Emissions Trading System (ETS). Current carbon prices hover between €70 and €90 per tonne of CO₂, contributing to elevated generation costs compared to historical averages.
In Greece, companies like PPC, Mytilineos, and Motor Oil operate gas plants that form the marginal generation layer. These facilities become crucial when renewable output falls short or during peak demand, thus determining the clearing price in day-ahead markets. Consequently, wholesale electricity prices in Greece have averaged between €100 and €140/MWh recently, with occasional spikes exceeding €200/MWh during tight supply conditions.
The impact of Greek pricing extends beyond its borders, particularly through the Bulgaria-Greece interconnection, which has a capacity of 1,200 to 1,500 megawatts (MW) and facilitates annual flows exceeding 10 to 12 terawatt-hours (TWh). When Greek prices rise, electricity flows from Bulgaria into Greece can elevate Bulgarian prices as well. Conversely, during low-price periods in Greece—often due to solar oversupply—electricity flows reverse, leading to lower prices in Bulgaria.
This interdependence creates a complex relationship between gas and electricity prices throughout South-East Europe. In Bulgaria, despite a diverse generation mix that includes nuclear power from Kozloduy NPP (~2 GW), coal from the Maritsa East complex, and renewables, electricity prices often align with those in Greece during peak times. Day-ahead prices can reach between €120 and €160/MWh even when local generation costs are lower.
Romania’s energy landscape features a balanced mix that includes hydroelectric power and nuclear generation from Cernavodă NPP (~1.4 GW). However, during high-demand periods or low hydro output, gas plants become marginal players that align Romanian prices with those observed regionally. Average electricity prices in Romania typically range from €80 to €110/MWh but can converge with higher regional levels when interconnections are fully utilized.
Serbia remains outside full market coupling yet is significantly influenced by cross-border price signals transmitted through its interconnections with Hungary and Bulgaria. The domestic generation primarily relies on coal (EPS fleet), which sets a baseline price but does not insulate Serbia from regional fluctuations. During periods of stress in neighboring markets, Serbian electricity prices tend to align closely with those across the border due to import dependencies.
The merit order within South-East Europe is increasingly dictated by gas at the margin. While renewable sources like solar and wind enter the market at minimal marginal costs—displacing more expensive generation when available—gas plants are activated during periods of low renewable output or high demand. This scenario leads to average prices being influenced by renewables while peak pricing remains tied to gas-fired generation.
This dual structure introduces notable volatility into the market. For instance, midday solar output can drive prices down to between €30 and €50/MWh; however, as solar generation diminishes later in the day, gas plants ramp up production and push prices back toward €100–150/MWh. The intraday price spread often ranges from €60 to €100/MWh—a characteristic feature of this market environment.
Renewable developers face both opportunities and challenges amid this volatility. While elevated peak prices can enhance revenue potential, concentrated solar generation during low-price periods may lead to reduced average capture prices—often falling below baseload benchmarks by €10–25/MWh in saturated nodes.
Energy storage systems emerge as vital tools for capitalizing on this volatility by shifting energy from low-price periods to peak hours. A 200 MWh battery system operating in Greece could exploit price spreads of €50–80/MWh, potentially generating annual revenues between €15 million and €30 million depending on usage rates. This capability transforms volatility into a revenue-generating opportunity while supporting equity internal rates of return (IRRs) between 12% and 18%.
Industries heavily impacted by carbon costs are increasingly seeking long-term renewable contracts as hedges against gas-driven price fluctuations. Power purchase agreements (PPAs) priced between €65 and €95/MWh offer stability compared to spot market exposure, effectively decoupling parts of industrial consumption from gas-linked pricing mechanisms.
From a financing perspective, the linkage between gas and power introduces both potential benefits and risks for stakeholders. High gas prices bolster electricity rates, enhancing revenue projections under various scenarios; however, lenders remain cautious about downside risks associated with volatile pricing environments. Financial models frequently adopt conservative price assumptions ranging from €70 to €90/MWh while conducting sensitivity analyses for higher-priced conditions.
The role of transmission infrastructure is crucial for moderating these dynamics. Projects such as the Trans-Balkan Corridor (€300–400 million) and enhancements to Greece-Bulgaria connections (€500 million+) improve cross-border electricity flow capabilities, helping mitigate price discrepancies and extreme market volatility. Nevertheless, divergent generation mixes across countries combined with limited interconnection capacity ensure that gas will continue to play a significant role in determining marginal pricing throughout much of the region.
Data analytics platforms like Electricity.Trade are becoming essential for tracking interactions among gas prices, electricity rates, and cross-border flows. By analyzing correlations among LNG benchmarks and day-ahead pricing patterns, market participants can better anticipate shifts in pricing dynamics and optimize their operational strategies accordingly.
Looking forward, while the influence of gas on price formation may evolve with increased renewable capacity reducing average reliance on fossil fuels, the necessity for flexible generation will persist. Gas plants may operate fewer hours but will likely continue setting prices during critical demand periods—reinforcing their importance in establishing marginal electricity costs across South-East Europe’s energy landscape.
In conclusion, understanding the interplay between electricity pricing mechanisms necessitates a comprehensive grasp of gas markets and LNG supply chains within South-East Europe. The region’s power market cannot be viewed independently; rather it is intricately linked with global trends and local regulatory frameworks that shape its economic landscape.
