South-east European day-ahead electricity prices moved sharply lower for 20 August 2026, but the decline was far from uniform. The dominant move was a broad correction across Hungary and the SEE markets after the elevated levels seen earlier in the week, while Italy moved in the opposite direction and preserved a sizeable western premium. HUPX settled at €161.34/MWh, down €6.60/MWh day on day, Romania’s OPCOM was almost identical at €160.86/MWh, Slovenia at €161.89/MWh and Croatia at €161.36/MWh. Further south and east, the correction became much 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 was the regional low, while the newsletter’s Italian benchmark rose to €180.89/MWh, producing a nearly €49/MWh gap between the cheapest and most expensive markets.
The size of the daily correction is more important than the absolute price level. A simple unweighted basket of HUPX, OPCOM, IBEX, HENEX, BSP, CROPEX, SEEPEX, ALPEX, BELEN and MEMO fell from roughly €163.94/MWh to €152.03/MWh, a decline of about 7.3 per cent in one 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 markedly, falling €17.80/MWh to €148.22/MWh, whereas Austria lost only €2/MWh to €165.16/MWh. Italy was the exception, adding €5.40/MWh. The result was a considerably wider geographical price structure: HUPX stood at a €13.11/MWh premium to Germany, Serbia traded €29.35/MWh below Hungary, and Italy carried a €19.55/MWh premium to HUPX.
This was not a return to genuinely low regional pricing. Hungary’s €161.3/MWh base price remained about 5 per cent above its seven-day average of €153.5/MWh. Romania’s €160.9/MWh was more than 6 per cent above its seven-day average, and Greece, despite one of the largest daily falls, remained almost 13 per cent above its seven-day mean of €129.9/MWh. Serbia’s €132/MWh was also around 9 per cent above its seven-day average. The session therefore looks more like a correction from the extreme tightness of the previous several trading days than a structural break lower. The regional curve is still carrying a summer scarcity premium, particularly outside the solar-heavy midday hours.
The more striking trading signal sits inside the hourly profiles. HUPX’s peak block averaged only €148.9/MWh, while off-peak power averaged €173.8/MWh, an inversion of almost €25/MWh. The Hungarian price reached its daily minimum of €107.7/MWh at hour 14, before climbing to €211.8/MWh at hour 20. Romania showed an almost identical structure, with a €148/MWh peak, €173.7/MWh off-peak, a minimum of €106.1/MWh and an evening maximum of €211.5/MWh. Slovenia’s spread was similarly inverted, with peak power at €150.3/MWh against €173.5/MWh off-peak. The shape matters more for trading than the daily base-price decline: value is increasingly concentrated in the evening ramp, while solar-exposed daytime hours are becoming materially cheaper.
Greece provided the clearest example. HENEX’s base price fell to €146.6/MWh, but the peak block averaged just €119.4/MWh, compared with €173.7/MWh off-peak. The day’s minimum fell to only €33/MWh at hour 10, while the maximum reached €211.2/MWh at hour 20. Bulgaria displayed the same pattern at a less extreme level, with peak power at €133.9/MWh, off-peak at €173.7/MWh, a minimum of €69.1/MWh and maximum of €211.2/MWh. Croatia was more closely aligned with Hungary, with a €149.2/MWh peak and €173.5/MWh off-peak. The Mediterranean and Balkan markets are effectively pricing two different systems within the same delivery day: a heavily supplied solar period and a much tighter evening and overnight balance.
The western Balkans were less converged but showed the same underlying structure. Serbia’s base price of €132/MWh was the regional low, with its peak block at €127.3/MWh, off-peak at €136.7/MWh, a daily low of €75.3/MWh and a maximum of €200/MWh. Montenegro averaged €150.1/MWh, but its maximum rose to €221.1/MWh, while Albania reached €220.6/MWh despite a base price of €152.5/MWh. Albania’s off-peak block at €170.1/MWh was more than €35/MWh above its peak value. North Macedonia recorded a similar inversion, with peak 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 hours 19-22 are exposed to a very different price environment from solar-heavy daytime production.
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 about 3.7 per cent. 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 per cent. As local supply expanded faster than demand, the region’s net import requirement dropped from 1,601 MW to only 667 MW, a reduction of 934 MW. Imports from the core AT+SK direction fell from 2,044 MW to 1,383 MW, while regional exports towards Italy increased from 450 MW to 915 MW. In a single session, SEE therefore needed substantially less northern supply while sending more than twice as much electricity westward toward the higher-priced Italian market.
Renewables added another layer to that shift. The 20 August forecast put regional solar production at 8,666 MW, up 1,793 MW from the previous day, while wind was forecast at 1,539 MW, an increase of 634 MW. Together, the two technologies were expected to add roughly 2.43 GW of output day on day. That increase is large enough to explain much of 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 absorbing more electricity while requiring less external supply because the generation side of the balance improved 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. Yet the structure varied dramatically by block. Hungary was marginally a net exporter during the peak block, at 97 MW, but imported an average 2,105 MW during off-peak hours. Base flows included around 786 MW entering 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 hides a system that moves from heavily import-dependent overnight conditions to near balance during solar-supported daytime periods.
That 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 own intraday profile was even more deeply 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; it reflected Germany’s more aggressive repricing lower alongside reduced core-to-SEE imports.
Greece illustrates the connection between renewables, flows and hourly price formation even more clearly. Greek consumption was 6,834 MW, generation 7,629 MW and net exports 795 MW. But the block split was extreme: Greece exported an average 1,516 MW during peak hours, compared with only 73 MW off-peak. Its base flow toward Italy increased to around 412 MW, while Greek exports into North Macedonia remained around 401 MW. At the Bulgaria border the direction reversed by block: Greece exported strongly during peak hours but became an importer during the off-peak period. The same hours in which HENEX prices collapse are therefore the hours when Greek surplus electricity is pushed outward into neighbouring systems.
Romania, meanwhile, moved considerably closer to balance. Consumption was almost unchanged at 5,670 MW, versus 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 137 MW. Romania was actually a 560 MW net exporter in the peak block, while importing 834 MW off-peak, another clear demonstration of the daytime-versus-night-time split. Romanian flows toward Hungary averaged 786 MW on a base basis and rose above 2.1 GW in peak hours, while Romania simultaneously imported substantial volumes from Bulgaria. OPCOM’s near-perfect convergence with HUPX at €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, sending out an average 1,294 MW, up from 1,224 MW on 19 August. Generation reached 5,334 MW against consumption of 4,040 MW. Its base exports included 846 MW toward Romania, 314 MW toward Serbia and 130 MW toward North Macedonia. The Bulgaria-Greece border again reveals the solar-driven hourly reversal: the daily base position showed Bulgaria exporting 104 MW to Greece, but the peak block was 456 MW in the opposite direction, while off-peak Bulgaria exported 664 MW southward. That reversal closely mirrors the very low Greek peak price and stronger Greek daytime export surplus.
Italy provided the destination for much of the surplus and remained the main premium market. Italy South averaged about €180.9/MWh, with a peak block of €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 or Serbia. Even Italy’s low-priced hours therefore retained significant value relative to the weakest SEE and central European periods. The strengthening of SEE exports toward 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 eased €1/MWh to €147/MWh, and September lost €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 per cent over the preceding trading window shown in the report, compared with only 0.4 per cent for Germany, while Italy gained 2.1 per cent. Hungarian prompt risk has therefore repriced much more aggressively than the neighbouring western contracts.
Fuel markets were not providing a corresponding 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 and Q4 coal increased $1/t to $127/t. At the same time, the Hungarian-German forward spread remained large, at €23.50/MWh for Week 35, €25/MWh for Week 36, €24/MWh for September and €20/MWh for Cal-26. Prompt power therefore weakened despite broadly firm fuel inputs, pointing back toward weather, renewable production, cross-border flows and system balance as the dominant drivers of the session rather than a change in thermal generation economics.
The 20 August session leaves SEE with a more complex trading 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 toward Italy doubled. Yet the hourly market retained very large scarcity premiums after solar production faded. HUPX still moved from €107.7/MWh at its daytime low to €211.8/MWh in the evening, Greece from €33/MWh to €211.2/MWh, and Albania and Montenegro reached evening highs above €220/MWh. The dominant tradable feature is no longer simply whether the regional base price is rising or falling; 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 SEE, Central Europe and Italy.
