The evolving relationship between gas markets and power pricing in Southeast Europe (SEE) and Hungary has reached a critical juncture, characterized by fragmented marginality rather than a continuous load curve. The trading session on February 26, 2026, exemplified this shift, revealing that while gas remains pivotal to price formation, its role is increasingly constrained and time-sensitive. Understanding the gas–power marginality matrix is essential for interpreting price behavior and volatility in the region, as well as for developing effective trading strategies that account for the complex interactions among fuel, carbon emissions, and renewable energy sources.
During this session, forward gas prices experienced an upward trend, with near-term contracts at the Central European Gas Hub rising alongside carbon allowances. Traditionally, such movements would lead to higher power prices; however, day-ahead power prices in many areas, especially Hungary, saw significant declines. This divergence underscores the limitations of single-factor fuel-driven models and highlights the necessity of viewing marginality as a multi-dimensional construct influenced by time, location, and technology availability.
Fundamentals in gas pricing were supportive during this period. Near-term gas forwards advanced due to ongoing geopolitical risks, robust liquefied natural gas (LNG) demand, and tightening supply expectations as winter storage withdrawals continued. Concurrently, EU carbon allowances maintained their upward trajectory, further disadvantaging coal-fired generation. Although coal prices softened slightly, this was not enough to offset the carbon costs associated with coal generation. Consequently, gas remained the preferred thermal marginal fuel whenever renewables and imports fell short.
However, this scenario is contingent upon specific conditions. On February 26, increased wind and solar generation significantly altered the marginal stack throughout much of the day. Wind output surged by several hundred megawatts compared to previous sessions, while solar generation also rose sharply. These zero-marginal-cost energy sources displaced gas and coal from the merit order during daylight hours, shifting the marginal price-setting towards imports or renewables instead of thermal generation. As a result, gas’s influence on pricing was effectively suspended during off-peak and shoulder periods despite rising gas prices.
This trend was particularly evident in southern SEE markets such as Serbia, North Macedonia, and Greece, where price behavior reflected a renewables-dominated regime for extended periods. Daytime prices plummeted due to surplus solar generation coupled with limited export capacity. In these instances, gas-fired plants were either fully displaced or operated at minimal stable loads, thus having no impact on price formation. During these hours, the link between gas prices and power prices became negligible.
The dynamics shifted dramatically as renewable output diminished in the evening hours. Particularly between 18:00 and 21:00, gas re-emerged as the dominant marginal fuel across most interconnected markets. During these peak periods, price signals tightened around clean spark economics; even minor fluctuations in gas availability or carbon pricing could lead to significant impacts on power prices as the system transitioned from surplus to scarcity rapidly. This period highlighted how gas could set power prices intensely but only for brief intervals.
In Hungary specifically, while average prices fell on February 26, evening peak prices remained elevated due to reliance on gas-fired generation and imports to meet peak demand as renewables declined. In these critical hours, increases in both gas forwards and carbon allowances had substantial implications for pricing despite their minimal effect on daily averages. For market participants, this indicates that exposure to gas-linked power price risk is increasingly concentrated within a limited timeframe, heightening both potential rewards and risks.
Carbon pricing plays a vital role in shaping this matrix by continuously undermining coal’s competitiveness and narrowing its ability to set marginal prices. Even when coal prices decrease, the carbon component ensures that coal remains less favorable compared to gas in most markets. This structural pressure accelerates the transition towards a system where gas becomes the sole thermal marginal fuel during periods when renewables cannot satisfy demand. The outcome is a marginality regime that is sharper and more volatile than previously observed.
The absence of sufficient flexible demand or storage capacity exacerbates this situation in southern SEE markets. As renewable capacity grows, midday surpluses increase pressure on prices downward while compressing margins for all thermal generation. Conversely, acute scarcity arises during evening ramps when gas units must quickly respond to rising demand amid declining renewable output. The lack of storage solutions prevents these markets from smoothing transitions efficiently, resulting in extreme intraday price fluctuations. Thus, gas marginality becomes not only temporal but also highly unstable.
This evolving landscape has significant implications for forward markets and hedging strategies. Traditional baseload hedges that assume a stable relationship between gas and power prices throughout the day are becoming increasingly misaligned with current realities. As gas influences pricing for fewer hours each day, baseload power contracts show diminished correlation with gas forwards while peak contracts exhibit heightened sensitivity. This decoupling challenges conventional risk management strategies and underscores the importance of granular time-specific hedging approaches.
Strategically speaking, movements in gas prices will continue to affect power prices asymmetrically moving forward. Upside risks in gas pricing will disproportionately impact peak-hour power rates while downward shifts may have limited effects on average prices if renewables dominate during daylight hours. This asymmetry favors trading strategies that focus on peak pricing exposure rather than broad baseload movements.
The integration of LNG into regional supply routes introduces additional complexity to this dynamic landscape. Developments related to the Vertical Gas Corridor and increased LNG inflows into Greece and neighboring markets are anticipated to improve gas availability over the medium term. While this may help stabilize some aspects of gas price volatility, it will not eliminate fundamental characteristics of the marginality matrix; ample gas supply will still see renewables displacing thermal generation during significant portions of each day.
In summary, the trading session on February 26 underscored that understanding the relationship between gas and power pricing in SEE and Hungary requires moving beyond linear models. Marginality has evolved into a dynamic interaction shaped by renewable output variability, transmission constraints, and carbon costs. For market participants navigating this landscape, recognizing when and where these factors exert influence is crucial for effective decision-making.
