Electricity pricing in South-East Europe is ultimately anchored not in renewables or coal, but in gas. More precisely, it is anchored in liquefied natural gas and the infrastructure that brings it into the region. While renewable capacity is expanding rapidly and coal remains part of the system, the marginal price—the price that clears the market during peak hours—is increasingly set by gas-fired generation, particularly in Greece and, through interconnection, across the broader Balkan system.
This linkage between gas and power is not theoretical. It is structural, measurable and persistent. It defines the price floor, the volatility envelope and the upside scenarios across all major electricity markets in the region, including Greece (HEnEx), Bulgaria (IBEX), Romania (OPCOM), Hungary (HUPX) and indirectly Serbia, which remains outside full market coupling but is fully exposed through cross-border flows.
The starting point of this structure is Greece’s LNG import system. The Revithoussa terminal, with capacity of approximately 7 bcm per year, has long been the primary entry point for LNG into the Greek system. Its expansion and operational optimisation have increased flexibility, allowing for rapid response to market conditions. The addition of the Alexandroupolis FSRU, with capacity of 5.5 bcm per year, fundamentally changes the scale and redundancy of supply, effectively doubling Greece’s ability to import LNG and positioning it as a regional gas hub.
Gas entering these terminals is priced against global LNG benchmarks, primarily influenced by Asian demand, European storage levels and geopolitical supply dynamics. Delivered gas costs into Greece typically translate into power generation costs of €70–120/MWh, depending on plant efficiency (typically 50–60% for combined-cycle gas turbines) and carbon costs under the EU ETS. With carbon prices in the range of €70–90 per tonne CO₂, gas-fired generation costs are structurally elevated compared to historical norms.
These gas plants—operated by companies such as PPC, Mytilineos and Motor Oil—form the marginal generation layer in Greece. When renewable output is insufficient or demand peaks, these plants set the clearing price in the day-ahead market. As a result, Greek wholesale electricity prices have averaged €100–140/MWh in recent trading periods, with spikes above €200/MWh during periods of tight supply or elevated gas prices.
The influence of this pricing extends beyond Greece’s borders. The Bulgaria–Greece interconnection, with capacity of 1,200–1,500 MW and annual flows exceeding 10–12 TWh, transmits these price signals northward. During periods of high Greek prices, electricity flows from Bulgaria into Greece, raising prices in Bulgaria as supply is redirected. Conversely, during periods of low Greek prices—typically driven by solar oversupply—flows reverse, exporting electricity northward and depressing prices in neighbouring markets.
This bidirectional interaction creates a dynamic linkage between gas prices and electricity prices across the region. In Bulgaria, where the generation mix includes nuclear (Kozloduy NPP, ~2 GW), coal (Maritsa East complex) and renewables, gas does not dominate the generation stack. Yet prices frequently align with Greek levels during peak periods, reflecting the influence of cross-border flows. Day-ahead prices in Bulgaria can reach €120–160/MWh during such periods, even when domestic generation costs are lower.
Romania exhibits a more balanced dynamic due to its diversified generation mix, including hydro, nuclear (Cernavodă NPP, ~1.4 GW) and gas. However, during periods of high demand or low hydro output, gas plants become marginal, aligning Romanian prices with broader regional levels. Average prices in Romania typically range between €80–110/MWh, but convergence with Greek or Hungarian markets occurs when interconnection capacity is fully utilised.
Serbia, despite being outside full market coupling, is fully exposed to these dynamics. The Serbia–Hungary and Serbia–Bulgaria interconnections transmit price signals into the Serbian market, where domestic generation—largely based on coal (EPS fleet)—sets a baseline but does not isolate the system. During periods of regional stress, Serbian prices align with neighbouring markets, reflecting both import dependency and cross-border arbitrage.
The merit order in South-East Europe is therefore increasingly shaped by gas at the margin. Renewable generation—solar and wind—enters the system at near-zero marginal cost, displacing higher-cost generation during periods of availability. However, when renewable output declines, gas plants are called upon to meet demand, setting the price for the entire market. This creates a system where average prices are influenced by renewables, but peak and marginal prices are defined by gas.
This dual structure introduces volatility. During midday periods of high solar output in Greece, prices can fall to €30–50/MWh, well below gas-driven levels. In extreme cases, prices approach zero, particularly when interconnection capacity is insufficient to export surplus generation. As the day progresses and solar output declines, gas plants ramp up, pushing prices back toward €100–150/MWh. The resulting intraday spread—often €60–100/MWh—is a defining feature of the market.
For renewable developers, this volatility is both an opportunity and a challenge. High peak prices increase potential revenues, but concentration of solar generation in low-price periods reduces capture prices. Without mitigation, solar projects may realise average prices €10–25/MWh below baseload benchmarks, particularly in saturated nodes.
Storage integration is the primary mechanism for capturing value from gas-driven volatility. By shifting energy from low-price periods to peak hours, batteries effectively arbitrage the gas price signal. A 200 MWh battery system operating in Greece can capture spreads of €50–80/MWh, generating annual revenues of €15–30 million, depending on utilisation. This transforms volatility from a risk into a revenue stream, supporting equity IRRs of 12–18%.
Industrial offtake further interacts with this structure. Energy-intensive industries exposed to carbon costs are increasingly seeking to hedge against gas-driven price volatility through long-term renewable contracts. PPAs priced at €65–95/MWhprovide a stable alternative to spot market exposure, effectively decoupling part of industrial consumption from gas-linked pricing. This creates a parallel pricing layer within the market, anchored in renewable supply rather than marginal generation.
From a financing perspective, the gas-to-power linkage introduces both upside and risk. High gas prices support higher electricity prices, improving revenue assumptions in base and upside scenarios. However, lenders remain cautious, focusing on downside resilience. Financial models typically assume conservative price scenarios in the €70–90/MWh range, with sensitivity analyses capturing higher-price environments. This approach reflects the recognition that gas prices—and therefore electricity prices—are subject to global market dynamics beyond regional control.
Transmission infrastructure plays a critical role in moderating this linkage. Projects such as the Trans-Balkan Corridor (€300–400 million) and Greece–Bulgaria reinforcements (€500 million+) increase the ability to move electricity across borders, smoothing price differences and reducing extreme volatility. However, as long as generation mixes remain divergent and interconnection capacity is finite, gas will continue to define the marginal price in large parts of the region.
Data platforms such as Electricity.Trade are increasingly used to track the interaction between gas prices, electricity prices and cross-border flows. By analysing correlations between LNG benchmarks, day-ahead prices and congestion patterns, market participants can better anticipate price movements and optimise strategies.
Looking ahead, the role of gas in price formation is likely to evolve but not disappear. The expansion of renewable capacity will reduce average reliance on gas, but the need for flexible, dispatchable generation will remain. Gas plants are likely to operate fewer hours but set prices more frequently during those hours, reinforcing their role in defining the marginal cost of electricity.
Hydrogen and other low-carbon alternatives may eventually alter this dynamic, but their impact within the 2030 horizon remains limited. For the foreseeable future, LNG and gas-fired generation will continue to anchor the price structure of South-East Europe’s electricity market.
The implication for investors and developers is clear. Understanding electricity pricing in the region requires understanding gas markets, LNG flows and the infrastructure that connects them. The power market cannot be analysed in isolation; it is an extension of the gas market, shaped by global dynamics and local constraints.
In this environment, value is created not only by generating electricity but by positioning assets within the system defined by gas. Projects that can capture peak pricing, mitigate exposure to low-price periods and integrate flexibility will outperform those that rely on static assumptions. The gas-to-power linkage is therefore not just a pricing mechanism; it is the central axis around which the region’s energy economics revolve.
