Why LNG still drives peak power prices across South-East Europe

For investors tracking South-East Europe’s power market, the key risk factor is not renewable build-out alone—it is how LNG pricing and gas-fired dispatch translate into marginal electricity prices. Even as solar and wind expand, the system’s clearing price during peak hours continues to be shaped by gas plants, with knock-on effects across multiple national markets through cross-border trading.

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.

Gas-to-power transmission: where price signals travel

This linkage between fuel costs and power pricing is structural rather than temporary. It defines the price floor, volatility range and upside scenarios across major electricity markets in the region—Greece (HEnEx), Bulgaria (IBEX), Romania (OPCOM), Hungary (HUPX)—and indirectly affects Serbia, which remains outside full market coupling but stays exposed through cross-border flows.

The mechanics start with Greece’s LNG import capability. The Revithoussa terminal, with capacity of approximately 7 bcm per year, has long been a primary entry point for LNG into the Greek system. Its expansion and operational optimisation have increased flexibility so supply can respond more quickly to changing market conditions.

A second facility adds scale and redundancy: Alexandroupolis FSRU, with capacity of 5.5 bcm per year. Together, these assets effectively double Greece’s ability to import LNG and strengthen its position as a regional gas hub.

LNG benchmarks feed generation costs—and then wholesale prices

LNG delivered into Greece is priced against global benchmarks. Those benchmarks are primarily influenced by Asian demand, European storage levels and geopolitical supply dynamics. Delivered gas costs 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 faces structurally higher cost levels than historical norms. In practice, this means that when renewables do not cover demand or when consumption peaks, gas becomes the marginal layer that sets day-ahead clearing prices.

Marginal setting shows up differently across national markets

The effect is visible in Greece first. Gas plants operated by companies such as PPC, Mytilineos and Motor Oil form the marginal generation layer when they are needed most. During those periods, Greek wholesale electricity prices have averaged €100–140/MWh, with spikes above €200/MWh during tight supply or elevated gas-price conditions.

Bulgaria illustrates how interconnection transmits those signals northward. The Bulgaria–Greece interconnection, with capacity of 1,200–1,500 MW and annual flows exceeding 10–12 TWh, moves electricity based on relative pricing between systems. When Greek prices rise sharply, electricity tends to flow from Bulgaria into Greece—raising Bulgarian prices as local supply is redirected. When Greek prices fall—often linked to solar oversupply—flows reverse direction and export surplus electricity northward while depressing neighbouring market prices.

This bidirectional interaction creates alignment at peak times even though Bulgaria’s generation mix includes nuclear (Kozloduy NPP, ~2 GW), coal (the Maritsa East complex) and renewables. Day-ahead prices in Bulgaria can reach €120–160/MWh during peak periods even when domestic generation costs are lower.

Romania shows a more diversified pattern because hydro output alongside nuclear (Cernavodă NPP, ~1.4 GW) reduces reliance on any single fuel source most of the time. Still, when demand rises or hydro output falls low enough for scarcity conditions to emerge, Romanian gas plants become marginal again—pulling Romanian day-ahead pricing toward broader regional levels. Average Romanian prices typically range between €80–110/MWh, but convergence occurs when interconnection capacity allows full utilisation across borders.

Serbia remains outside full market coupling yet does not sit apart from these dynamics. Through links such as (as described) (a) (as described) (a) (as described)

The Serbia–Hungary and Serbia–Bulgaria interconnections transmit price signals into Serbia’s market environment where domestic generation—largely coal-based via EPS fleet—sets a baseline but cannot isolate pricing from regional stress events. During those episodes Serbian prices align with neighbouring markets due to import dependency and cross-border arbitrage.

A merit order built on renewables at zero cost—but priced by gas at peaks

The region’s merit order increasingly reflects a two-part structure: renewables displace higher-cost units when available because they enter at near-zero marginal cost; however, when solar or wind output declines or demand surges beyond what renewables can cover, gas plants are called upon to meet residual load—and then set the price for everyone in that clearing interval.

This design produces pronounced intraday volatility. In Greece during midday periods of high solar output, prices can fall to €30–50/MWh, sometimes approaching zero when surplus cannot be exported due to limited interconnection capacity. As solar output fades later in the day and dispatch shifts back toward thermal units—including gas—prices move back toward roughly €100–150/MWh. The resulting intraday spread often sits around €60–100/MWh.

Sponsors face volatility risk—but storage turns it into value creation

This volatility cuts both ways for renewable developers: high peak prices raise potential revenues during scarcity intervals but concentration of solar production around low-price periods can reduce capture rates if projects do not hedge timing risk. Without mitigation measures such as shifting output profiles or securing contracts aligned with peak value windows, solar projects may realise average prices €10–25/MWh below baseload benchmarks..