Southeast European day-ahead electricity markets staged a sharp Monday rebound on 31 August as trading moved away from the weekend, with peak-hour prices recovering strongly while reduced availability of imports from core European markets widened several regional spreads.
Hungary’s HUPX day-ahead baseload price increased by €46/MWh from Sunday to €173.41/MWh, while Romania advanced by €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. This left much of the interconnected eastern and central SEE market concentrated within a relatively narrow €171–175/MWh range.
Serbia remained the clear outlier. SEEPEX gained €35/MWh day on day but settled at only €132.21/MWh, leaving the Serbian market €41.20/MWh below Hungary. Montenegro was also priced below the regional core at €162.69/MWh, €10.72/MWh under HUPX, while North Macedonia settled at €152.58/MWh, €20.84/MWh below Hungary.
The move therefore represented less a broad tightening of the entire Southeast European market and more a return of the weekday peak structure following exceptionally weak Sunday daytime prices.
On HUPX, the Monday peak contract averaged €145.2/MWh, compared with only €60.8/MWh on Sunday, an increase of more than €84/MWh. Off-peak prices moved far less, rising from €194.1/MWh to €201.6/MWh. Hungary’s hourly minimum increased from negative €1.4/MWh on Sunday to €84.4/MWh on Monday, while the maximum reached €254.3/MWh in hour 19.
The profile indicates that the disappearance of the extreme weekend daytime discount was the main driver behind the higher baseload settlement. Lower Sunday demand combined with strong solar generation had compressed peak prices, while the return of weekday consumption restored value during daytime and evening hours.
Serbia showed the same pattern even more clearly. SEEPEX peakload rose from just €44.9/MWh on Sunday to €123.3/MWh on Monday, while off-peak prices actually declined from €149.5/MWh to €141.1/MWh. Serbian baseload therefore climbed to €132.2/MWh from €97.2/MWh despite remaining well below neighbouring markets. The Monday hourly range was also exceptionally broad, stretching from €50/MWh to €233.2/MWh.
For short-term traders, this distinction is important because the €35/MWh increase in Serbian baseload does not represent an equal repricing across the entire curve. The main adjustment occurred during peak hours, reinforcing the value of storage, flexible hydro and dispatchable generation capable of shifting supply away from weaker daytime periods and towards the evening ramp.
Core import availability tightens
Cross-border flows provide an additional explanation for the sharp rise across the main SEE markets despite lower combined consumption.
Combined Hungary and SEE consumption was indicated at 30,866 MW, down 495 MW day on day. Regional generation, however, increased to 28,281 MW from 27,515 MW, allowing net imports to fall substantially to 2,585 MW from 3,846 MW. Imports from the Austria-Slovakia core into Hungary and Slovenia declined particularly sharply, reaching 2,947 MW compared with 4,407 MW previously, a reduction of 1,460 MW.
The market signal suggests that the marginal value of available cross-border supply increased even though the region as a whole required less imported electricity.
The relationship with Germany illustrates the shift most clearly. German day-ahead baseload settled at only €111.85/MWh, leaving Hungary at a €61.56/MWh premium, approximately €9.7/MWh wider than the previous day. Austria, meanwhile, reached €177.99/MWh, while the Italian benchmark stood at €197.31/MWh.
The relatively low German price therefore had limited ability to pull Southeast European prices lower. The Germany-Hungary spread became significantly more important for regional price formation than the Hungary-Greece differential, which stood at only €2.18/MWh.
From a trading perspective, Monday left Hungary, Romania, Bulgaria, Greece, Slovenia, Croatia and Albania in near-convergence, while the region remained sharply separated from Germany to the northwest and from Serbia and parts of the western Balkans to the southeast.
Serbia becomes the regional discount hub
Serbia’s €41/MWh discount is particularly striking because the country remained a net importer rather than developing into a major surplus market.
Average Serbian consumption was forecast at 3,574 MW, compared with generation of 3,089 MW, resulting in net imports of approximately 485 MW. Serbia was importing on average from Hungary, Romania, Bulgaria, Croatia and Bosnia and Herzegovina while exporting towards Montenegro and North Macedonia.
Average imports from Bulgaria were around 276 MW, from Romania 160 MW and from Hungary 174 MW. At the same time, Serbia scheduled approximately 160 MW towards Montenegro and 50 MW towards North Macedonia.
The persistence of a €41/MWh Serbian discount despite net imports suggests that the price separation cannot be explained simply by excess domestic supply. Local bidding behaviour, available cross-border capacity, bilateral scheduling and limitations on transferring Serbian-priced electricity into higher-priced Hungarian and Croatian markets appear to be sustaining a distinct SEEPEX zone.
That creates a significant cross-border trading signal. The theoretical Serbia-Hungary spread is substantial, but capturing it depends on transmission availability and the direction of hourly commercial flows rather than on the baseload differential alone.
Montenegro displayed another unusual regional configuration. Domestic demand remained dependent on imports, with consumption at 485 MW against generation of 342 MW. At the same time, the country scheduled approximately 569 MW towards Italy, effectively operating as an electricity transit corridor between the western Balkans and the higher-priced Italian market.
With Italian power around €197/MWh and Montenegro at €162.69/MWh, this westward price pull remains an important factor shaping regional flows.
Romania tightens while Bulgaria exports
Romania’s €174.90/MWh settlement reflected a relatively tight domestic balance. Consumption was indicated at 4,552 MW compared with only 3,639 MW of generation, producing net imports of roughly 913 MW. Romania imported significant volumes from Bulgaria and Hungary while continuing to supply Serbia.
Bulgaria occupied the opposite side of the regional balance. Generation reached approximately 4,935 MW against consumption of 3,848 MW, resulting in average exports of around 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 remained close to €171–175/MWh. Bulgarian surplus was being absorbed by neighbouring markets rather than creating a separate low-price zone.
Forward curve keeps SEE premium
Near-term derivatives continued to indicate a substantial Hungarian premium over Germany. Hungarian week-36 power was priced at €160/MWh, week 37 at €161/MWh and September at €165/MWh. The corresponding HU-DE spread stood at €40.50/MWh for week 36, narrowing to €27/MWh for week 37 and September. CEGH gas was indicated at €68.36/MWh, while EUA allowances traded around €82.73/t.
The forward curve therefore suggests that Monday’s 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 generation can still push individual hours sharply lower, but transmission constraints and the evening ramp can quickly restore scarcity premiums as renewable output declines.
The combination of higher Monday peak prices and persistent Serbia-Hungary and Germany-Hungary separations shows that cross-border transmission capacity, rather than aggregate regional demand alone, is increasingly determining where the highest short-term trading value is concentrated.
