Thermal generation across South-East Europe remained broadly stable in aggregate during Week 16, but the internal composition of that output tells a more consequential story for traders, utilities and policymakers. Beneath the headline of only marginal weekly growth, the region saw an important rebalancing between gas and coal, with gas-fired plants recovering part of their flexibility role while coal, and especially lignite, continued to provide strategic baseload support in systems where renewable and hydro variability left little room for complacency.
Across the region, thermal generation increased by just 0.18% week-on-week to 4,300 GWh, a figure that at first glance suggests little change in dispatch conditions. But that stability masks a clear internal shift. Coal and lignite output declined by 3.35%, while gas-fired generation rose by 3.31%, indicating that system operators and market participants leaned more heavily on flexible gas assets to manage short-term balancing, even as solid fuels retained a central structural role in several national systems.
This pattern is consistent with a market environment shaped less by pure demand growth and more by renewable intermittency, hydro weakness and changing cross-border flows. In such a setting, thermal assets are not simply filling a uniform baseload function. Instead, they are being split more clearly into two categories: gas as a responsive balancing technology, and coal or lignite as an anchor of supply security where domestic fleets remain operational and politically protected.
Italy provides the clearest example of this duality. The country posted the largest absolute increase in thermal generation during the week, adding 179 GWh, or 14.1%, driven primarily by higher gas-fired production and an additional rebound in coal output from a low prior base. This reflects a familiar Italian pattern. When domestic demand rises and renewable output becomes less reliable, Italy falls back not only on imports but also on its thermal fleet, especially gas. In a high-price environment, these plants become central to price formation because they frequently set the marginal unit in day-ahead and intraday markets.
Hungary also recorded a strong increase in thermal output, up 23.7%, while Croatia posted a particularly sharp percentage increase, 156.5%, albeit from a low base. Both cases highlight the same structural logic. In markets with limited hydro flexibility and uneven renewable output, thermal generation remains the fastest dispatchable solution for covering gaps. Gas-fired units are especially valuable in these systems because they can respond more effectively to short-term changes in wind and solar output than coal units can.
Serbia’s case was different, and more revealing from a structural perspective. Thermal generation rose by 19.7%, led overwhelmingly by lignite, which increased by 19.8%. This underlines Serbia’s continued dependence on domestically fuelled coal generation, not as a temporary fallback but as a foundational element of system security. In Serbia’s market design and generation structure, lignite remains the backbone asset able to absorb variability in domestic renewables and hydrology while containing direct exposure to imported gas.
That lignite-led stability has a strategic logic even if it comes with efficiency, emissions and maintenance challenges. In a week when broader European prices rose and cross-border conditions tightened, Serbia’s relatively flat price performance compared with some neighbouring markets suggests that domestic thermal availability helped cushion the system from sharper price escalation. That does not mean Serbia was insulated, since it moved from slight exporter to net importer, but it does show that thermal baseload still matters materially in regional price resilience.
Greece presents yet another variation. Its thermal output was broadly flat, rising just 0.02%, but this stability concealed an internal substitution. Lignite generation dropped by 16.9%, while gas output increased modestly by 2.4%. This reflects the country’s longer-term transition away from domestic lignite, combined with the need to keep gas plants available as the balancing engine of a more renewable-heavy power system. Greece is not abandoning thermal power; it is repurposing it. The role has shifted from traditional baseload to flexibility and reserve support, with gas plants increasingly carrying that burden.
Türkiye, the region’s largest thermal producer, moved in the opposite direction. It registered a substantial decline of 13.0%, or 263 GWh, with both coal and gas generation falling. This is important because Türkiye was simultaneously the region’s lowest-priced market and a stronger exporter during the week. The combination suggests that abundant lower-cost generation, particularly wind, displaced thermal units and allowed prices to fall sharply. In that sense, Türkiye offered a glimpse of what happens when renewable output is strong enough to suppress both gas burn and wholesale prices at the same time.
Romania and Bulgaria saw slight contractions in thermal output, with reductions of 1.4% and 2.7% respectively. These are small changes numerically, but they matter in markets where hydro and renewable shifts can quickly alter the need for dispatchable backup. Bulgaria’s position as an exporter means that thermal availability also has a regional value beyond domestic balancing. Romania, meanwhile, was hit by both weaker hydro and falling demand, creating a more mixed dispatch pattern.
What emerges from all this is not a story of thermal decline, but of thermal repositioning. Gas and coal are no longer serving identical system functions. Gas is increasingly the technology of flexibility, short-cycle balancing and marginal price setting, especially in more liberalised or gas-linked markets. Coal and lignite, where they remain operational, are increasingly the technologies of strategic firmness, reserve capacity and domestic sovereignty.
That distinction matters for market analysis because it changes how price signals should be interpreted. A fall in gas prices, such as the decline in TTF during Week 16 to an average of €42.47/MWh, does not automatically produce lower power prices if gas plants are being used primarily for flexibility rather than broad merit-order displacement. Lower gas prices may reduce the cost of balancing, but if the system is tight due to hydro weakness, solar softness or transmission constraints, wholesale prices can still rise. That is exactly what happened in Week 16.
It also matters for investment strategy. In the past, discussion around thermal power in Europe often treated gas as the transition fuel and coal as the phase-out fuel. In SEE, the picture is more complicated. Gas does play the transition role, especially where interconnection and market design reward flexibility. But lignite and coal continue to hold strategic value in countries where domestic reserves, legacy infrastructure and supply security concerns outweigh decarbonisation timelines in actual dispatch decisions.
This has implications for clean spark spreads and clean dark spreads, although the report does not quantify these directly. In high-price weeks like this one, gas plants can recover margin even when running as flexible peakers, provided they are called often enough during tight hours. Coal units, especially lignite units with lower direct fuel cost but higher carbon intensity, may continue to run where capacity remuneration, policy support or system necessity keeps them commercially viable despite carbon exposure.
The real challenge for the region is that this thermal rebalancing is occurring in parallel with rising renewable penetration, but without enough fast flexibility resources to smooth volatility. Battery storage remains limited. Demand response is still immature. Pumped storage is available in some markets but not on a scale sufficient to transform balancing conditions across the region. That leaves gas plants performing an outsized role in intra-day flexibility while coal fleets remain embedded as reliability insurance.
For regulators, that raises uncomfortable questions. If coal is still needed for stability, how should markets price that service? If gas is increasingly called not as baseload but as flexible reserve, how should capacity mechanisms, balancing markets and ancillary services compensate those plants? And if wholesale prices continue to rise during weeks when gas falls, what does that mean for the credibility of fuel-linked market narratives?
For traders, the lesson is practical rather than theoretical. Thermal dispatch in SEE must be read through a system lens, not a commodity lens alone. Lower gas prices may help, but they are only one variable. Wind volatility, hydro levels, cross-border exports and local thermal outages often matter more in determining whether gas units set price and whether coal units remain deeply in merit.
Week 16 showed that clearly. The region did not move into a gas-led easing cycle simply because TTF softened. Instead, thermal generation reconfigured internally to respond to a more volatile supply environment. Gas recovered some of its flexibility role, coal retained strategic importance, and power prices rose in most markets anyway.
That leaves SEE in a structurally hybrid position. It is not a pure renewables market, and it is not a traditional fossil market either. It is a system where thermal assets still define reliability, but increasingly through differentiated roles. Gas carries the burden of responsiveness. Coal and lignite carry the burden of firmness. Until storage, grid reinforcement and demand-side flexibility scale materially, that division of labour is likely to remain one of the central realities of the region’s power market.
SEE demand fragmentation points to uneven industrial recovery and weather-led weakness in regional power consumption
Electricity demand across South-East Europe rose only marginally in Week 16, but the regional aggregate concealed a far more uneven pattern underneath. Consumption trends diverged sharply by market, with Italy driving most of the increase while several Balkan and Central SEE systems posted meaningful declines. For traders and system analysts, that fragmentation matters because it suggests the region is not moving in a single macroeconomic direction. Instead, it is being shaped by a mix of local weather conditions, national industrial structures, cross-border trade positioning and differing levels of exposure to electricity prices.
Total electricity demand across the SEE region reached 15,379 GWh in Week 16, a modest increase of 1.04% week-on-week. On paper, that looks like a stable system with mild consumption growth. In reality, however, it was an uneven market in which one large economy, Italy, accounted for most of the rise, while multiple regional markets either stagnated or contracted.
Italy was the standout on the upside. Demand rose by 6.35%, or 291 GWh, making it the dominant source of regional growth. Given Italy’s sheer scale within the regional dataset, that was enough to lift the overall SEE total despite weakness elsewhere. The increase likely reflected a mix of factors, including stronger commercial or industrial load, more temperature-sensitive consumption, and the country’s structurally higher responsiveness to short-term economic and climatic changes. Whatever the precise mix, the result was clear: Italy once again acted as the demand centre of gravity for the wider market.
Hungary also posted a notable increase of 3.55%, while Greece, Bulgaria and Croatia registered smaller gains of 0.63%, 0.54% and 1.45% respectively. These increases point to relatively steady domestic consumption patterns without signalling an outright surge in industrial recovery. They look more like stable operating conditions than a broad-based growth breakout.
By contrast, Romania and Serbia recorded much sharper demand declines, at -5.64% and -4.89% respectively. Türkiye, despite remaining the largest absolute consumption market in the dataset, also saw demand slip by 1.41%. Those reductions matter because they occurred during a week when prices were rising across much of the region. In other words, the demand picture was not one of strength chasing supply. It was one of uneven and in some cases weakening consumption meeting tighter supply-side conditions.
That distinction is crucial. When prices rise on the back of strong demand growth, the market story is usually one of economic momentum or weather-driven system stress. But when prices rise while several countries are actually consuming less, the message is different. It points to structural weakness in consumption, alongside a supply stack that is becoming more volatile and less forgiving. Week 16 fits the second pattern.
For Serbia, the decline in demand is particularly interesting when viewed together with its flat price profile and higher thermal output. Lower consumption may have helped the domestic system avoid even sharper price escalation, especially given the continued importance of lignite in Serbia’s generation mix. But the fact that Serbia shifted from slight exporter to net importer despite falling demand suggests that domestic generation and cross-border balancing conditions were under more pressure than the headline demand figure alone would imply. Lower load did not translate into clear system looseness.
Romania presents a similarly layered picture. A 5.64% fall in demand should ordinarily relieve pressure on the market. Yet Romania still recorded a strong price increase during the week. That points directly to the importance of supply-side weakness, notably weaker hydro and lower wind output, in overriding the demand effect. In other words, Romanian consumption fell, but available low-cost generation fell faster or became less reliable, leaving the market tighter in price terms.
Türkiye remains the outlier in the opposite direction. Demand declined slightly, but prices collapsed by nearly 26%, reflecting a much stronger interaction between softer consumption and abundant lower-cost generation. Türkiye’s near-doubling of wind output helped create exactly the kind of market response absent elsewhere in the region: lower demand plus stronger renewables resulted in sharply lower prices and stronger export potential. That makes Türkiye less representative of SEE’s broader pattern and more of a domestic-market exception within it.
The fragmentation in demand also says something about the industrial complexion of the region. Italy’s rise likely reflects the fact that it remains a diversified, electricity-intensive industrial economy with deeper market liquidity and greater load responsiveness. Hungary’s growth may also indicate industrial resilience, potentially tied to manufacturing and data-centre or automotive-related load pockets. Serbia and Romania, on the other hand, appear to reflect softer local conditions, which may include weather moderation, industrial caution or simply weak week-on-week comparatives.
The report itself does not break consumption down by sector, but the country-level pattern allows some grounded inference. Where demand rises strongly in a large industrial market like Italy, the effect on regional power balances is immediate because that load must be met through a combination of domestic generation and imports. Where demand falls in smaller or more coal-dependent systems like Serbia, the effect may be less visible in price terms if supply flexibility is limited or cross-border conditions are tight. This asymmetry is one reason why regional demand cannot be read mechanically as a single macro signal.
For market participants, the practical conclusion is that SEE demand should increasingly be analysed as a mosaic rather than a block. Aggregate regional growth can be misleading if it is dominated by one or two countries. A headline increase of just over 1% sounds neutral. But once disaggregated, it reveals one major importing market pulling harder, several countries treading water, and a handful experiencing clear demand softness. That kind of pattern has different implications for spreads, dispatch and interconnector use than a synchronised regional rise would have.
It also affects the reading of power price elasticity. In some markets, higher prices may already be suppressing discretionary industrial load. In others, industrial demand may be resilient enough that price increases do not significantly reduce consumption in the short run. The contrast between Italy and Romania in Week 16 is instructive. Italy consumed more despite already having the region’s highest price. Romania consumed less even before accounting for the stronger weekly price increase. That implies very different demand elasticity profiles and industrial structures.
From a systems perspective, fragmented demand increases the burden on cross-border balancing. When one major market like Italy pulls more electricity while nearby systems such as Serbia or Romania consume less, flows do not simply fall. Instead, they can be redirected toward the highest-value destination, which in this case remains Italy. That is one reason why net imports into Italy rose further during the week even though parts of SEE were showing softer load. Consumption weakness in one part of the region does not necessarily reduce overall system tightness if another structurally short market is absorbing the available surplus.
There is also a seasonal angle. Mid-April is a transition period in which both heating and cooling loads can be muted relative to winter or summer extremes, making week-on-week shifts more vulnerable to weather noise. That may explain part of the decline in Serbia and Romania. But even if weather was the immediate driver, the market significance remains. Transitional-season demand softness should ordinarily make the system more comfortable. The fact that prices rose anyway across most of SEE shows how much supply-side volatility now dominates.
This is one of the most important messages from Week 16. Demand is no longer the clean primary variable it once was in regional price analysis. It still matters, of course, especially in Italy. But increasingly, the shape and location of demand matter more than the regional total. A large increase in one structurally short market can outweigh declines in several smaller or more self-supplied systems. That makes granular national analysis essential.
Looking ahead, this fragmentation in demand will become more important, not less. SEE economies are not following identical industrial trajectories. Some are integrating more deeply with European manufacturing chains. Others remain more exposed to domestic macro conditions, weather-sensitive consumption or regulated end-user pricing structures that alter how wholesale costs feed through to demand. As power systems decarbonise and electrification begins to widen across transport, heating and industry, these divergences may become more pronounced.
For utilities and traders, that means demand forecasting must become more country-specific and more sensitive to local industrial calendars, weather patterns and cross-border incentives. For policymakers, it means regional energy planning cannot rely on simple averages. Grid investment, market design and capacity adequacy frameworks all need to reflect the fact that SEE demand is structurally uneven.
Week 16 delivered a concise version of that reality. Regional consumption grew, but only marginally. Italy carried the increase. Hungary added support. Serbia, Romania and Türkiye weakened. Prices still rose across most of the region because supply dynamics overpowered aggregate demand softness.
The result is a market where demand fragmentation is no longer background noise. It is part of the central story. Consumption patterns across SEE are increasingly differentiated, and those differences now interact directly with renewable volatility, thermal dispatch and cross-border flows to determine market outcomes. In that sense, Week 16 was less a story of regional demand growth than of regional demand imbalance, and that imbalance is becoming one of the defining features of the SEE power market.