Southeast European day-ahead electricity prices rebounded sharply for Monday, 31 August, as the market moved out of the weekend, with a pronounced recovery in peak-hour values and reduced availability of imports from the core European markets widening regional spreads.
Hungary’s HUPX day-ahead baseload price rose €46/MWh from Sunday to €173.41/MWh, while Romania climbed €50.1/MWh to €174.90/MWh. Slovenia settled at €173.61/MWh, Albania at €173.42/MWh, Croatia at €172.28/MWh, and Bulgaria and Greece both at €171.24/MWh. The result produced a relatively tight €171-175/MWh cluster across much of the interconnected eastern and central SEE market.
The major exception was Serbia. SEEPEX rose by €35/MWh on the day but remained at only €132.21/MWh, leaving Serbia at a striking €41.20/MWh discount to Hungary. Montenegro was also below the regional core at €162.69/MWh, or €10.72/MWh below HUPX, while North Macedonia settled at €152.58/MWh, a discount of €20.84/MWh.
The price move was therefore less a uniform tightening of southeast Europe than a re-establishment of the weekday peak structure after exceptionally weak Sunday daytime prices.
On HUPX, the Monday peak contract averaged €145.2/MWh, compared with just €60.8/MWh on Sunday, an increase of more than €84/MWh. Off-peak prices changed much less, rising from €194.1/MWh to €201.6/MWh. Hungary’s hourly minimum jumped from a negative -€1.4/MWh on Sunday to €84.4/MWh for Monday, while the Monday maximum reached €254.3/MWh at hour 19.
That profile points to the disappearance of the extreme weekend daytime discount as the principal driver of the higher baseload settlement. Solar output and low Sunday demand had compressed peak prices, but the return of weekday load restored value to daytime and evening generation.
The same pattern was especially visible in Serbia. SEEPEX peakload jumped from only €44.9/MWh on Sunday to €123.3/MWh on Monday, even as off-peak prices declined from €149.5/MWh to €141.1/MWh. Serbia’s baseload consequently rose to €132.2/MWh from €97.2/MWh despite the continuing discount to neighbouring markets. Its Monday hourly range remained exceptionally wide, from €50/MWh to €233.2/MWh.
This is important for short-term traders because the €35/MWh rise in the Serbian baseload does not represent a simple across-the-curve increase. It was primarily a peak-hour repricing. The structure continues to favour storage, flexible hydro and dispatchable generation capable of shifting volumes from weaker daytime periods towards the evening ramp.
Core import availability tightens
Cross-border data also help explain why the main SEE markets moved so strongly higher even though aggregate consumption was not increasing.
Combined Hungary and SEE consumption was indicated at 30,866 MW, 495 MW lower day on day. Regional generation, however, increased to 28,281 MW from 27,515 MW, allowing net imports to fall sharply to 2,585 MW from 3,846 MW. Imports from the Austria-Slovakia core into Hungary and Slovenia fell particularly strongly, to 2,947 MW from 4,407 MW, a decline of 1,460 MW.
The price signal therefore suggests that the marginal value of available cross-border supply increased even as the region required less imported electricity overall.
This is reflected most clearly in the widening relationship with Germany. German day-ahead baseload settled at only €111.85/MWh, leaving Hungary at a €61.56/MWh premium, around €9.7/MWh wider than the previous day. Austria, by contrast, reached €177.99/MWh, while the Italian benchmark stood at €197.31/MWh.
The result illustrates how little the relatively cheap German power was able to suppress prices further southeast. The Germany-Hungary separation is now considerably more relevant to regional price formation than the Hungary-Greece spread, which was only €2.18/MWh.
In practical trading terms, the market on Monday was almost converged from Hungary through Romania, Bulgaria, Greece, Slovenia, Croatia and Albania, while remaining sharply disconnected from Germany on one side and from Serbia and parts of the western Balkans on the other.
Serbia becomes the regional discount hub
Serbia’s €41/MWh discount is particularly notable because the country remained a net importer rather than emerging as a large surplus market.
Average Serbian consumption was forecast at 3,574 MW, against generation of 3,089 MW, producing net imports of around 485 MW. Serbia was importing on average from Hungary, Romania, Bulgaria, Croatia and Bosnia and Herzegovina while exporting towards Montenegro and North Macedonia.
Imports from Bulgaria averaged 276 MW, Romania 160 MW and Hungary 174 MW on a baseload basis. Serbia simultaneously scheduled around 160 MW towards Montenegro and 50 MW towards North Macedonia.
The persistence of a €41/MWh Serbian discount despite that net import position suggests the separation cannot be explained simply by domestic supply surplus. Instead, the combination of local bidding, available cross-border capacity, bilateral scheduling and constraints on transferring Serbian-priced electricity farther into the higher-priced Hungarian and Croatian markets appears to be maintaining a distinct SEEPEX price zone.
That creates an unusually strong cross-border trading signal. The theoretical Serbia-Hungary spread is large, but monetising it depends on available transmission rights and the hourly direction of commercial flows rather than the baseload price differential alone.
Montenegro showed another distinctive cross-border structure. Its domestic balance remained import-dependent, with consumption at 485 MW and generation at 342 MW, but the country simultaneously scheduled roughly 569 MW towards Italy, effectively acting as an electricity transit corridor between the western Balkans and the higher-priced Italian market.
With Italy around €197/MWh and Montenegro at €162.69/MWh, that westward pull remains an important influence on Balkan flows.
Romania tightens while Bulgaria exports
Romania’s €174.90/MWh settlement also corresponds with a relatively tight domestic balance. Consumption was indicated at 4,552 MW against just 3,639 MW of generation, leaving net imports at about 913 MW. Romania was importing heavily from Bulgaria and Hungary while continuing to supply Serbia.
Bulgaria was positioned on the opposite side of the regional balance. Its generation reached around 4,935 MW against 3,848 MW of consumption, resulting in average exports of 1,087 MW. Commercial flows included approximately 600 MW towards Romania and 276 MW towards Serbia.
This helps explain why Bulgarian, Romanian and Greek prices nevertheless converged near €171-175/MWh: Bulgarian surplus was being absorbed by neighbouring systems rather than creating an isolated low-price zone.
Forward curve keeps SEE premium
Near-term derivatives continued to price a substantial Hungarian premium over Germany. Hungarian week-36 power stood at €160/MWh, week 37 at €161/MWh and September at €165/MWh. The corresponding HU-DE spread was €40.50/MWh for week 36, falling to €27/MWh for week 37 and September. CEGH gas was indicated at €68.36/MWh, while EUA allowances were around €82.73/t.
The forward structure therefore implies that the extreme €61.56/MWh spot premium over Germany is expected to narrow, but not disappear.
For the immediate market, Monday’s trading reinforces a familiar late-summer SEE pattern: strong solar output can still depress individual hours, but transmission constraints and the evening ramp rapidly restore scarcity premiums once renewable generation declines. The sharp rise in Monday peak prices, combined with the persistent Serbia-Hungary and Germany-Hungary separations, shows that cross-border capacity rather than aggregate regional demand is increasingly determining where the highest short-term trading value sits.