The electricity market in South-East Europe is increasingly influenced by liquefied natural gas (LNG) dynamics, establishing a critical link between gas and power pricing. As renewable energy sources expand and coal remains part of the energy mix, it is gas-fired generation that increasingly determines the marginal price—the price that clears the market during peak demand hours. This trend is particularly evident in Greece and extends through interconnected systems across the Balkans.
Greece’s LNG infrastructure serves as a pivotal foundation for this pricing structure. The Revithoussa terminal, with an annual capacity of approximately 7 billion cubic meters (bcm), has historically been the main entry point for LNG into Greece. Recent expansions and operational optimizations have enhanced its flexibility, enabling quicker responses to market fluctuations. The introduction of the Alexandroupolis floating storage and regasification unit (FSRU), which can handle an additional 5.5 bcm per year, has effectively doubled Greece’s LNG import capacity, establishing it as a regional gas hub.
The pricing of gas at these terminals is influenced by global benchmarks shaped by Asian demand, European storage levels, and geopolitical factors. Consequently, the cost of delivered gas translates into power generation expenses ranging from €70 to €120 per megawatt-hour (MWh), contingent upon plant efficiency—typically around 50-60% for combined-cycle gas turbines—and carbon costs under the European Union Emissions Trading System (ETS). Elevated carbon prices, currently between €70 and €90 per tonne of CO₂, contribute to higher operational costs for gas-fired plants compared to historical levels.
In Greece, companies such as PPC, Mytilineos, and Motor Oil operate these gas plants, which form the marginal generation layer. During periods when renewable output falls short or demand peaks, these plants establish the clearing price in day-ahead markets. Recent trading data indicates that wholesale electricity prices in Greece have averaged between €100 and €140/MWh, with occasional spikes exceeding €200/MWh during tight supply or high gas price scenarios.
The implications of this pricing structure extend beyond Greece’s borders due to interconnections with Bulgaria. The Bulgaria-Greece interconnection allows for a capacity of 1,200 to 1,500 megawatts (MW) and facilitates annual flows exceeding 10-12 terawatt-hours (TWh). High electricity prices in Greece often lead to increased imports from Bulgaria, consequently raising Bulgarian prices as supply is redirected. Conversely, during low-price periods in Greece—often driven by solar overproduction—electricity flows northward from Greece to Bulgaria, exerting downward pressure on local prices.
Bulgaria’s generation mix includes nuclear power from Kozloduy NPP (~2 GW), coal from the Maritsa East complex, and renewables; thus, while gas does not dominate its generation stack, prices frequently align with those in Greece during peak times due to cross-border flow influences. Day-ahead prices can reach €120-160/MWh even when domestic generation costs are lower.
Romania presents a more balanced scenario owing to its diverse energy sources including hydroelectric power and nuclear facilities like Cernavodă NPP (~1.4 GW). However, high demand or low hydro output can push gas plants into marginal positions that align Romanian prices with regional trends. Typical average prices range from €80 to €110/MWh but can converge with Greek or Hungarian markets when interconnection capacities are maximized.
Serbia remains outside full market coupling yet is significantly affected by these dynamics through interconnections with Hungary and Bulgaria. The Serbian market experiences price signals reflective of regional trends despite primarily relying on coal for domestic generation via the EPS fleet. During regional stress events, Serbian prices tend to align closely with those of neighboring countries due to import dependencies and cross-border trading opportunities.
The merit order across South-East Europe increasingly reflects gas pricing at its margins. Renewable energy sources like solar and wind displace higher-cost generation during favorable conditions but rely on gas plants when their output diminishes or demand surges—thus defining peak market prices while average costs are influenced by renewables.
This duality introduces significant volatility within the market framework. For instance, during peak solar production hours in Greece, electricity prices can drop to levels between €30-50/MWh—substantially below those set by gas-driven generation. Conversely, as solar output wanes later in the day and reliance shifts back toward gas plants, prices typically rebound towards ranges of €100-150/MWh.
For renewable developers navigating this fluctuating landscape presents both challenges and opportunities; while high peak prices can enhance revenue potential, oversupply during low-price periods may lead to diminished capture rates—resulting in average earnings potentially falling €10-25/MWh below baseload benchmarks in saturated nodes.
Energy storage systems represent a vital strategy for capitalizing on this volatility by shifting energy consumption from low-price intervals to peak demand periods. A battery system with a capacity of 200 MWh operating within Greece could realize spreads between €50-80/MWh annually generating revenues estimated at €15-30 million based on utilization rates—a transformation that converts volatility into a revenue-generating mechanism supporting internal rates of return between 12-18%.
Industries heavily impacted by carbon pricing are increasingly pursuing long-term renewable contracts as hedges against volatile gas-driven electricity costs. Power purchase agreements (PPAs) priced from €65-95/MWh offer stability against fluctuating spot market rates while effectively decoupling segments of industrial consumption from direct exposure to gas-linked pricing mechanisms.
From a financial standpoint, the interplay between gas-to-power dynamics presents both risks and opportunities; elevated natural gas costs tend to bolster electricity prices enhancing revenue forecasts under optimistic scenarios. However, lenders remain vigilant regarding downside risks—often modeling conservative price projections within a range of €70-90/MWh while conducting sensitivity analyses for potential high-price environments reflecting broader global market influences beyond regional control.
Transmission infrastructure plays an essential role in mitigating price volatility across interconnected markets; initiatives such as the Trans-Balkan Corridor (€300-400 million) and upgrades along Greece-Bulgaria links (€500 million+) enhance capacity for cross-border electricity movement thereby smoothing out price disparities while reducing extreme volatility impacts. Nevertheless, divergent generation mixes coupled with limited interconnection capacities will likely ensure that natural gas continues to define marginal pricing across significant portions of South-East Europe’s energy landscape.
To navigate future developments effectively within this context requires an understanding not only of local electricity markets but also their intrinsic connections to global LNG flows and infrastructures that underpin them. As such dynamics evolve over time—with increasing reliance on renewable energy sources—the foundational role played by LNG and natural gas-fired generation will persist as central elements influencing the region’s electricity pricing framework well into the future.
