March trading in South-East European day-ahead power markets showed a clear link between fuel costs and price formation, even as liquidity patterns diverged sharply by country. Clearing prices rose across most exchanges following a rebound in gas prices that tightened the marginal cost base. For developers and grid planners, the episode underlines how quickly system economics can shift when thermal input costs move, particularly where hydro and renewables do not fully offset demand.
Price benchmarks climb after a weaker February
Average day-ahead prices moved higher after February softness, clustering in the €95–€120/MWh range across core SEE hubs. Italy stayed the most expensive market at €143.36/MWh, reinforcing its role as the regional price anchor. Hungary followed at €117.36/MWh and Croatia at €110.12/MWh, while Romania cleared at €105.15/MWh and Bulgaria at €103.51/MWh.
Greece and Serbia converged near €95/MWh, but Türkiye decoupled from the regional pattern with prices falling to €31.77/MWh. The split highlights how market fundamentals can diverge even within the same broader geography, affecting how reliably price signals translate into investment planning assumptions for new generation or storage.
Gas input costs drive thermal bid pressure
The upward correction in clearing prices was largely attributed to higher gas input costs as TTF futures moved above €50/MWh. That increase fed directly into thermal generation bids, tightening supply economics across day-ahead schedules. At the same time, lower hydro output across much of the region and uneven renewable generation reduced non-gas balancing options.
With supply more reliant on gas-fired units, price sensitivity increased, especially during periods when flexibility is needed most. For operators preparing grid modernization and dispatch strategies, this reinforces the importance of operational studies that test how wind and solar variability interact with hydro constraints and gas price pass-through.
Intraday volatility rises as solar compresses midday pricing
Daily and hourly price formation pointed to growing intraday volatility during March. Midday prices were typically compressed by solar output, reflecting stronger daytime generation effects on clearing levels. Evening peaks widened significantly, particularly in tighter systems such as Serbia.
In Serbia, balancing needs pushed prices sharply higher during ramping hours, indicating that real-time constraints can dominate system behavior even when day-ahead averages appear stable. This is relevant for battery energy storage system sizing and control design, since dispatch requirements often concentrate around evening ramps rather than midday generation peaks.
Liquidity remains concentrated; volumes diverge by market
Trading volumes showed a more uneven pattern than prices, with liquidity highly concentrated in a limited set of exchanges. Italy dominated regional activity with about 24.2 TWh traded during the month, far exceeding all other markets. Greece followed with around 4.37 TWh, while Bulgaria and Hungary each recorded volumes close to 2.8 TWh.
Romania traded roughly 1.35 TWh and Croatia about 0.75 TWh, while Serbia remained structurally illiquid at just 0.46 TWh. For market participants underwriting renewable integration or storage procurement frameworks, thin liquidity can amplify exposure to price spikes and complicate hedging assumptions used in CAPEX planning models.
Monthly volume changes point to shifting participation
Month-on-month volume movements diverged across countries. Greece recorded a +7.4% increase in traded electricity compared with February, while Italy posted a modest +2.6% rise that suggested stable demand and continued cross-border activity. Bulgaria also saw higher liquidity with volumes up +5.6%.
By contrast, Hungary and Romania saw declines of -7.8% and -10.0%, respectively, indicating softer demand or reduced trading opportunities. Serbia’s volumes increased by +12.3% month-on-month even though absolute levels remained low, emphasizing limited depth on SEEPEX; Croatia posted a marginal +2.3% increase.
Hub-and-spoke trading structure shapes operational exposure
Daily volume patterns confirmed a hub-and-spoke structure in regional trading activity. Italy consistently traded between 700–900 GWh/day, while Greece averaged 120–150 GWh/day and Bulgaria and Hungary ranged between 80–120 GWh/day. Serbia’s daily traded volumes remained below 20 GWh/day.
This structure helps explain why price volatility can be more pronounced in smaller markets despite lower traded volumes: limited liquidity can magnify the impact of supply-demand imbalances on clearing outcomes. For grid modernization programs that include transmission reinforcement or new interconnection studies, these differences matter when forecasting congestion risk and balancing requirements for variable renewables.
Non-linear links between price levels and trading depth
The relationship between clearing prices and volumes remained non-linear throughout March. High-liquidity markets such as Italy maintained elevated price levels due to their dependence on gas-fired generation rather than because of trading depth alone. Smaller markets with lower liquidity—especially Serbia—showed stronger price volatility despite lower volumes.
Markets with more diversified generation mixes such as Bulgaria and Romania recorded more moderate price increases alongside relatively stable liquidity levels. For developers planning wind and solar buildouts or BESS additions, this suggests that portfolio-level revenue assumptions should be stress-tested against both fuel-driven marginal cost shifts and local liquidity conditions.
Broader implications for renewable integration and investment readiness
March trading confirmed that SEE power markets remain structurally tied to gas price movements, while hydro variability and renewable output drive short-term divergences in outcomes across exchanges. Liquidity concentration persists in a limited number of markets, leaving smaller systems more sensitive to imbalances that can translate into sharper intraday pricing swings.
For investors, utilities, contractors preparing EPC packages, and developers advancing engineering studies toward permitting and procurement readiness, the key takeaway is operational: fuel-cost volatility plus constrained flexibility can quickly reshape day-ahead economics and balancing exposure—conditions that directly influence wind and solar curtailment risk assessments, transmission upgrade business cases, and battery dispatch design targets.