South-east European day-ahead electricity prices moved sharply lower for 20 August 2026, although the correction was uneven across the region. The main move was a broad decline across Hungary and SEE markets following elevated prices earlier in the week, while Italy moved in the opposite direction and maintained a significant western premium. HUPX settled at €161.34/MWh, down €6.60/MWh day on day, while Romania’s OPCOM was almost identical at €160.86/MWh. Slovenia settled at €161.89/MWh and Croatia at €161.36/MWh.
Further south and east, the correction was considerably deeper. Bulgaria fell to €153.82/MWh, Greece to €146.57/MWh, Serbia to €131.98/MWh, Albania to €152.48/MWh, Montenegro to €150.06/MWh and North Macedonia to €139.95/MWh. Serbia recorded the lowest regional price, while the Italian benchmark increased to €180.89/MWh, creating an almost €49/MWh gap between the cheapest and most expensive markets.
The scale of the daily correction is more significant than the absolute price level. A simple unweighted basket of HUPX, OPCOM, IBEX, HENEX, BSP, CROPEX, SEEPEX, ALPEX, BELEN and MEMO fell from approximately €163.94/MWh to €152.03/MWh, a decline of around 7.3% in a single session. Albania recorded the largest nominal decline at €25.50/MWh, followed by Serbia at €19.20/MWh, North Macedonia at €14.70/MWh, Bulgaria at €13.90/MWh and Greece at €13.30/MWh. Germany also weakened significantly, falling €17.80/MWh to €148.22/MWh, while Austria declined by €2/MWh to €165.16/MWh. Italy was the exception, gaining €5.40/MWh.
The resulting geographical price structure was considerably wider. HUPX traded at a €13.11/MWh premium to Germany, Serbia was €29.35/MWh below Hungary, and Italy carried a €19.55/MWh premium to HUPX.
The correction should nevertheless not be interpreted as a return to genuinely low regional prices. Hungary’s €161.34/MWh remained roughly 5% above its seven-day average of €153.5/MWh. Romania’s €160.86/MWh was more than 6% above its seven-day average, while Greece, despite one of the largest daily declines, remained almost 13% above its seven-day average of €129.9/MWh. Serbia’s €131.98/MWh was also around 9% above its seven-day average. The session therefore appears to represent a correction from the extreme tightness of the previous several trading days rather than a structural move towards lower prices.
The most important trading signal is visible in the hourly price profiles. HUPX’s peak block averaged just €148.9/MWh, while off-peak power averaged €173.8/MWh, producing an unusual inversion of almost €25/MWh. The Hungarian price reached a daily minimum of €107.7/MWh at hour 14, before climbing to €211.8/MWh at hour 20. Romania showed an almost identical pattern, with peak power at €148/MWh, off-peak at €173.7/MWh, a minimum of €106.1/MWh and an evening maximum of €211.5/MWh. Slovenia displayed a similar inversion, with peak power at €150.3/MWh against €173.5/MWh off-peak.
The shape of the curve is therefore becoming more important than the daily average. Value is increasingly concentrated in the evening ramp, while solar-heavy daytime hours are becoming materially cheaper.
Greece provided the clearest example. HENEX’s base price fell to €146.57/MWh, but its peak block averaged only €119.4/MWh, compared with €173.7/MWh off-peak. The Greek market reached a minimum of just €33/MWh at hour 10, before climbing to €211.2/MWh at hour 20. Bulgaria showed the same pattern, albeit less dramatically, with peak power at €133.9/MWh, off-peak at €173.7/MWh, a daily minimum of €69.1/MWh and a maximum of €211.2/MWh. Croatia remained more closely aligned with Hungary, with peak power at €149.2/MWh and off-peak at €173.5/MWh.
The Mediterranean and Balkan markets are increasingly pricing two different systems within the same delivery day: a heavily supplied solar period followed by a much tighter evening and overnight balance.
The western Balkans were less closely aligned with central European markets but displayed the same underlying structure. Serbia recorded the regional low at €131.98/MWh, with peak power averaging €127.3/MWh, off-peak at €136.7/MWh, a daily minimum of €75.3/MWh and a maximum of €200/MWh. Montenegro averaged €150.06/MWh, but its maximum reached €221.1/MWh. Albania reached €220.6/MWh despite a base price of €152.48/MWh. Albania’s off-peak block averaged €170.1/MWh, more than €35/MWh above its peak value. North Macedonia showed a similar inversion, with peak power at €124.6/MWh and off-peak at €155.3/MWh.
These profiles reinforce the increasing importance of flexibility rather than base-load energy value. Generators and storage assets capable of shifting output into the 19:00–22:00 period are exposed to a fundamentally different price environment from solar-heavy daytime generation.
The physical balance explains much of the downward move. Regional HU+SEE consumption increased to 32,506 MW from 31,360 MW, a day-on-day gain of 1,146 MW, or around 3.7%. Generation, however, recovered more strongly, rising from 29,758 MW to 31,839 MW, an increase of just over 2.08 GW, or approximately 7%.
As supply expanded faster than demand, the region’s net import requirement fell from 1,601 MW to just 667 MW, a reduction of 934 MW. Imports from the core Austria-Slovakia direction declined from 2,044 MW to 1,383 MW, while regional exports towards Italy increased from 450 MW to 915 MW. In a single trading session, SEE therefore required substantially less northern supply while sending more than twice as much electricity westward towards the higher-priced Italian market.
Renewables added another important layer. The 20 August forecast put regional solar production at 8,666 MW, up 1,793 MW from the previous day, while wind generation was forecast at 1,539 MW, an increase of 634 MW. Together, solar and wind were expected to add approximately 2.43 GW of generation day on day.
That increase helps explain the simultaneous combination of higher regional consumption, lower net imports and weaker peak-block prices. The market was not simply responding to falling demand. The region was consuming more electricity while requiring less external supply because generation increased even faster.
Hungary’s balance is particularly revealing. Hungarian consumption declined from 4,437 MW to 4,081 MW, while generation increased from 2,938 MW to 3,077 MW. The country’s net import requirement consequently narrowed from 1,500 MW to 1,004 MW, a reduction of roughly one-third.
The structure varied sharply by trading block. Hungary was marginally a net exporter during the peak block, at 97 MW, but imported an average of 2,105 MW during off-peak hours. Base flows included approximately 786 MW from Romania and 881 MW from Slovakia, while Hungary exported 411 MW to Croatia, 144 MW to Serbia and 352 MW to Slovenia on a base basis.
The daily average therefore masks a system that moves from heavy import dependence overnight to near balance during solar-supported daytime periods.
This also helps explain the sharp widening of the German-Hungarian price spread. HUPX declined, but Germany declined much faster. German base power fell to €148.22/MWh, leaving Hungary €13.11/MWh higher, compared with only around €2/MWh previously. Germany’s intraday profile was even more compressed, with peak power at €123.8/MWh, off-peak at €172.6/MWh and a midday minimum of €63.7/MWh.
The widening Hungarian premium therefore did not reflect a new upward move in Hungary. Instead, it reflected Germany’s more aggressive repricing lower alongside reduced core-to-SEE imports.
Greece provides an even clearer example of the connection between renewables, cross-border flows and hourly price formation. Greek consumption stood at 6,834 MW, generation at 7,629 MW and net exports at 795 MW. The block split was extreme: Greece exported an average of 1,516 MW during peak hours, compared with only 73 MW off-peak.
Its base flow towards Italy increased to approximately 412 MW, while exports to North Macedonia remained around 401 MW. At the Bulgaria border, the direction reversed depending on the trading block. Greece exported strongly during peak hours but became an importer during off-peak periods.
The same hours in which HENEX prices collapsed were therefore the hours when Greek surplus electricity was being pushed into neighbouring markets.
Romania also moved considerably closer to balance. Consumption was almost unchanged at 5,670 MW, compared with 5,693 MW a day earlier, but generation increased from 5,037 MW to 5,533 MW. Net imports consequently fell from 656 MW to just 137 MW.
Romania was actually a 560 MW net exporter during the peak block, while importing 834 MW off-peak, another clear demonstration of the daytime-versus-night-time split. Romanian flows towards Hungary averaged approximately 786 MW on a base basis and rose above 2.1 GW during peak hours, while Romania simultaneously imported substantial volumes from Bulgaria.
OPCOM’s near-perfect convergence with HUPX — €160.86/MWh versus €161.34/MWh — therefore sits on top of an increasingly active transit and balancing position rather than a static national deficit.
Bulgaria remained one of the region’s strongest net exporters, with average exports rising to 1,294 MW, from 1,224 MW on 19 August. Generation reached 5,334 MW, compared with consumption of 4,040 MW.
Base exports included 846 MW towards Romania, 314 MW towards Serbia and 130 MW towards North Macedonia. The Bulgaria-Greece border again revealed a solar-driven hourly reversal. Bulgaria’s daily base position showed exports of 104 MW to Greece, but the peak block saw 456 MW flowing in the opposite direction, while off-peak Bulgaria exported 664 MW southward.
That reversal closely mirrors Greece’s very low peak prices and stronger daytime export surplus.
Italy provided the destination for much of the surplus and remained the main premium market. Italy South averaged approximately €180.89/MWh, with peak power at €173/MWh and off-peak at €188.8/MWh. Its minimum price was still €153/MWh, dramatically higher than the daytime lows seen in Germany, Greece, Bulgaria and Serbia.
Even Italy’s cheapest hours therefore retained significant value relative to the weakest periods in SEE and central Europe. The increase in SEE exports towards Italy from 450 MW to 915 MW is consistent with that price signal: available interconnection capacity had a clear economic incentive to move electricity westward.
The forward market reinforced the view that the sell-off was concentrated in prompt electricity rather than being driven by cheaper fuels. Hungarian Week 35 power fell €4.50/MWh to €146.50/MWh, Week 36 declined €1/MWh to €147/MWh, and September fell €2.50/MWh to €156/MWh. The Cal-26 contract, by contrast, edged €0.50/MWh higher to €129/MWh.
Hungarian Week 35 had fallen 8.44% over the preceding trading window shown in the report, compared with only 0.4% for Germany, while Italy gained 2.1%. Hungarian prompt risk has therefore repriced much more aggressively than neighbouring western contracts.
Fuel markets were not sending the same bearish signal. CEGH gas stood at €64.51/MWh, up €0.70/MWh, while the Greek gas marker increased €0.60/MWh to €54.93/MWh. EUA allowances slipped only €0.60/t to €81.71/t. September coal rose $2/t to $124/t, while Q4 coal increased $1/t to $127/t.
At the same time, the Hungarian-German forward spread remained substantial, at €23.50/MWh for Week 35, €25/MWh for Week 36, €24/MWh for September and €20/MWh for Cal-26.
Prompt electricity therefore weakened despite broadly firm fuel inputs, pointing towards weather, renewable generation, cross-border flows and system balance as the dominant drivers of the session rather than a fundamental change in thermal generation economics.
The 20 August trading session leaves SEE with a more complex market structure than the fall in daily averages initially suggests. Base prices corrected across almost every market, regional generation recovered faster than consumption, net imports fell by more than half and exports towards Italy doubled.
Yet the hourly market retained very large scarcity premiums after solar production faded. HUPX moved from €107.7/MWh at its daytime low to €211.8/MWh in the evening, Greece from €33/MWh to €211.2/MWh, while Albania and Montenegro reached evening highs above €220/MWh.
The dominant trading feature is therefore no longer simply whether the regional base price is rising or falling. Increasingly, it is the widening value gap between solar-heavy daytime electricity and the evening ramp, with interconnection capacity determining how efficiently those surpluses and deficits can be redistributed across South-east Europe, Central Europe and Italy.