South East European day-ahead power markets moved sharply lower on Friday, 17 April 2026, with prices converging downward across nearly all hubs as a combination of stronger renewable generation and reduced import dependence softened the regional balance.
The Hungarian day-ahead benchmark on HUPX cleared at €99.37/MWh, marking a steep €28.3/MWh decline day on day, while Romania’s OPCOM followed closely at €99.29/MWh. Slovenia’s BSP settled at €99.80/MWh and Croatia’s CROPEX at €99.33/MWh, reinforcing a tightly coupled Central-Eastern price cluster around the €100/MWh level.
Further south, prices diverged more visibly under stronger solar penetration. Serbia’s SEEPEX dropped to €85.83/MWh (-€29.3/MWh), Bulgaria’s IBEX to €85.97/MWh (-€18.6/MWh) and Albania’s ALPEX to €84.44/MWh (-€13.4/MWh), while Greece remained the lowest-priced market at €77.40/MWh, reflecting deeper midday solar-induced price compression. Montenegro stood as an outlier, clearing at €100.68/MWh, maintaining a premium to regional peers despite the broader bearish trend.
The downward price correction was driven primarily by a rapid improvement in the regional supply-demand balance. Total generation increased to 29,714 MW, while consumption eased to 29,542 MW, effectively eliminating the need for net imports and shifting the system into a 585 MW export position. This marked a significant turnaround from the previous day’s more import-reliant structure.
Renewables played a decisive role in that shift. Wind output surged by +1,261 MW to 3,528 MW, while solar generation increased by +399 MW to 4,223 MW, together displacing higher-cost thermal generation. Gas-fired output fell sharply by -818 MW to 3,305 MW, indicating a clear merit-order impact, while coal generation edged lower to 4,411 MW. Hydropower remained the backbone of the system at 7,146 MW, though slightly reduced day on day, and nuclear generation held stable at 5,815 MW.
Despite the spot sell-off, the forward and fuel complex provided limited bearish confirmation. European carbon allowances rose to €74.69/t, while Austrian hub gas (CEGH) increased marginally to €44.06/MWh. Hungarian forward power contracts also strengthened, with Week 17 at €103.50/MWh, Week 18 at €96.50/MWh, and Cal-26 at €110.00/MWh, highlighting a divergence between short-term physical conditions and forward expectations.
Cross-border dynamics further reinforced the softer price environment. The Hungary-Germany spread narrowed sharply to -€5.3/MWh, down more than €22/MWh day on day, reducing arbitrage incentives for imports from core European markets. At the same time, imports from Austria and Slovakia into the HU+SEE region dropped by 747 MW, bringing total core inflows down to 696 MW, while overall regional net imports improved by 618 MW.
Intraday price profiles reflected typical spring conditions but without extreme stress signals. Across major markets, midday prices dropped toward low double-digit levels, with minimums recorded at €8.7/MWh in Hungary, €8.6/MWh in Romania, and near-zero levels in Greece. Peak-hour prices remained elevated but contained, with most markets topping out between €150/MWh and €165/MWh, indicating that while evening ramps persisted, they were not tight enough to sustain the higher price levels seen earlier in the week.
The regional flow structure continues to underline structural asymmetries. Over the past week, Hungary and Romania have acted as key redistribution hubs, exporting toward Croatia and further into the Western Balkans, while Serbia and Bosnia and Herzegovina remained structurally import-dependent. Greece and Albania exhibited typical southbound volatility linked to solar swings and interconnection constraints.
The trading signal from the session is clear: the SEE market has entered a renewables-driven soft phase, where incremental increases in wind and solar output rapidly compress prices across the curve. The convergence of Central-Eastern markets around €99–100/MWh suggests strong coupling under balanced conditions, while the sharper declines in Greece, Bulgaria, and Serbia point to localized oversupply during daylight hours.
Looking ahead, the persistence of this softer pricing regime will depend on renewable output stability and demand evolution over the weekend. With forecast consumption remaining around 29.5 GW and temperatures broadly stable, continued wind and solar strength would likely maintain downward pressure, particularly in southern markets. However, any drop in renewable generation could quickly restore evening tightness and push peak-hour prices back toward the €120–160/MWh range that remains embedded in intraday curves.