Spanish Market Analysis
Analysis of the Spanish energy market is key to understanding the dynamics and trends affecting the sector both locally and internationally. In this detailed analysis, we address the important factors influencing energy prices, supply and demand, and the latest regulatory policies. This comprehensive overview will allow you to keep up to date with weekly changes and anticipate possible market variations, both in Spain and in other relevant markets such as France.
September 2025
Key figures of the month
Table of Contents
Main takeaways
Power forwards for 2026 were little changed. France and Spain saw modest easing, with Cal’26 contracts drifting lower by less than 4 €/MWh. Italy remained the most expensive forward market, slipping slightly but holding well above 105 €/MWh. In contrast, Germany and the UK recorded small upticks, gaining around 0.5–1 €/MWh, suggesting limited tightening expectations into the medium term.
Gas forwards (Cal’26) slipped across the board. France, Spain, the UK, and Germany each lost around 0.2–0.4 €/MWh, while Italy declined the most at nearly 1.5 €/MWh. The relatively flat gas curve continues to contrast with the still-elevated forward power markets, highlighting the role of country-specific structural drivers — nuclear availability in France, renewables in Spain, and system tightness in Italy.
EU Allowances (EUA Dec’25) strengthened by nearly 5 €/t, rising to 78 €/tCO₂, reinforcing the cost pressure on fossil generation. Meanwhile, coal (ARA CIF Y+1) softened by about 7 $/t, a move insufficient to offset the increased carbon burden for coal-fired power plants.
Indicative clean spark spreads for Cal’26 (based on 55% CCGT efficiency) improved in most continental markets. France led the gains, with margins up more than 2 €/MWh, while Germany and Spain also recorded modest improvements. Italy was flat, maintaining its high-priced equilibrium, and the UK was the only major market where forward spark spreads narrowed slightly. This suggests that, despite higher carbon prices, falling forward gas and relatively resilient power forwards are improving the outlook for gas-fired generation profitability outside the UK.
France is experiencing the largest forward premium, around 24 €/MWh, indicating expectations of tighter supply or rising marginal costs in the future compared to today’s very soft spot market. The spot price has plummeted, dropping nearly 20 €/MWh since August. In Spain, prices are holding steady, with the Cal’26 futures nearly aligning with the spot price, showing a relatively balanced outlook. However, there’s been a slight dip of about 7 €/MWh from the previous month.
Italy remains the most expensive market for both spot and forward prices. The small forward discount of approximately −3.7 €/MWh suggests that the current tightness may ease somewhat in the near term, yet prices are still hovering above 109 €/MWh. In Germany, the forward price sits just slightly above the spot price, about 3 €/MWh, reflecting a mild carry. Prices have firmed up, increasing by more than 6 €/MWh.
Although data for the UK spot market is currently unavailable, the Cal’26 futures are positioned in the middle range at around 91 £/MWh, falling between Germany and Italy. The August reference price was approximately 57 £/MWh, which is lower than the average price recorded in September of 66.4 £/MWh.
Energy demand and generation mix
Seasonal peaks are evident in the winter months of January and February 2025, as well as in July and August 2025, when generation and demand surpass 23–25 TWh, reflecting heating and cooling needs. By contrast, May 2025 shows a marked dip in generation, falling below demand and indicating potential maintenance periods or weaker renewable output. Across most other months, generation slightly exceeds demand, underscoring stable supply conditions, though the narrower margins in spring and early autumn suggest moments of tighter system balance. This decline suggests the influence of unusually mild weather, leading to reduced energy consumption during this period.
However, energy demand resulted higher level in September 25 than in ’24 even after its decrease after the summer period. This indicates a market that, while tight, maintains a balanced dynamic, with generation consistently meeting or slightly exceeding the evolving demands of consumers.
In September 2025, wind energy accounted for 18.6% of the mix, rebounding from 16.0% in the prior month but still below the 21.8% recorded a year earlier. This reflects the typical volatility of wind patterns, which remain seasonally dependent.
Solar photovoltaic (PV) maintained a strong presence at 23.2%, slightly down from the previous month’s 24.8% but notably higher than the 19.7% observed a year before. PV continues to consolidate its role as a reliable backbone of summer generation, providing stability in periods of high demand.
Hydro power held steady around 7.8%, consistent with recent months and only marginally above the 7.6% recorded previously. This stability suggests average hydrological conditions without major swings in reservoir or inflow levels.
Nuclear energy contributed 20.9%, marking a modest decline compared to 21.7% the month before and 23.5% a year earlier. While still central to the baseload, the data highlights a gradual rebalancing between nuclear and renewables.
Combined Cycle Gas Turbines (CCGT) represented 17.0%, down slightly from 17.9% the month prior but higher than the 13.5% contribution seen a year earlier. This shows how gas remains a flexible balancing technology, increasing its role when renewables dip.
Source: Haya Energy Solutions
Contributions from other renewables (3.8%) and other non-renewables (8.8%) remained stable, reinforcing their function as consistent but minor players in the overall mix.
Taken together, renewables (wind, PV, hydro, and others) delivered over 53% of generation in September 2025, with PV and wind making up the bulk of this share. The combination of strong PV output and recovering wind demonstrates the continued rise of renewables, while CCGT and nuclear remain essential for system reliability and balancing seasonal intermittency.
Energy prices & market panorama
- Winter peak: Prices rose sharply from November 2024 through February 2025, averaging above 110 €/MWh, with wide volatility driven by strong seasonal demand and tighter supply.
- Spring trough: A steep correction followed in April–May 2025, with averages dropping below 50 €/MWh, reflecting softer demand and abundant renewable generation.
- Summer rebound: From June onward, prices recovered to ~70–80 €/MWh, stabilizing through the summer months, though volatility remained evident before easing slightly in September 2025.
Source: Haya Energy Solutions
Between September 2024 and September 2025, monthly spot base prices showed a pronounced seasonal cycle with episodes of volatility. Prices began the period in autumn 2024 at moderate levels of around 70–80 €/MWh, before climbing steadily through the winter months. By December 2024 and January 2025, average prices were consistently above 110 €/MWh, with wide price distributions reflecting cold-weather demand and supply pressures. February 2025 maintained elevated levels, but from March onward a clear downward correction emerged, with prices falling below 50 €/MWh by April and reaching a low near 30 €/MWh in May 2025. This spring dip coincided with abundant renewable output and softer demand, leading to compressed averages and narrow spreads.
From June 2025, prices recovered sharply, rising back toward 70–80 €/MWh during the summer. July and August showed stable averages in this range, though the wide boxplot ranges indicate episodes of strong intramonth volatility. By September 2025, the market settled slightly lower, averaging just below 70 €/MWh, suggesting a return to more balanced conditions.
Overall, the year demonstrates a typical seasonal pattern: high winter prices driven by demand peaks, a sharp spring trough under favourable renewable and demand conditions, and a summer rebound with increased volatility. The broad spread of price distributions throughout the period highlights ongoing market sensitivity to short-term drivers such as weather, renewables availability, and fuel price dynamics.
Market trends and futures
Source: Haya Energy Solutions
In September 2025, power prices showed small but mixed movements compared to August. The very short-term contracts (M+1 and M+2) rose slightly, while some of the near-term periods (M+3 and Q+2) slipped lower. The longer-dated contracts (Y+1 and Y+2) inched higher, suggesting a modest increase further out on the curve.
For gas, the picture was more uniform: prices declined across almost all delivery periods, with the biggest drops around the quarterly products (down around 2–3%). Only the very long-dated Y+2 contract stayed flat. This points to a softer fuel market overall.
By contrast, carbon prices (EUAs) moved sharply higher, climbing by just over 6% for both 2025 and 2026 delivery. This added pressure on thermal generation costs.
As a result, the Clean Spark Spread (CSS), which measures the profitability of gas-fired power plants, worsened across the board. Even though gas was cheaper, the rise in CO₂ costs outweighed that benefit, leaving gas-fired margins more negative than the previous month.
Despite the decline in gas prices, clean spark spreads remained firmly negative, highlighting the continuing lack of profitability for gas-fired generation. While some near-term margins showed slight improvement, spreads along the longer-term curve deteriorated. This deterioration occurred because the decline in power prices outpaced the reduction in fuel costs.
Overall, the August update depicts a landscape of easing fundamentals for power and gas, paired with firmer carbon pricing. This scenario leaves gas-fired plants structurally challenged and underscores the ongoing importance of renewables and low-carbon technologies in the energy generation mix.
SP Baseload Power price (€/MWh)
SP Peak load Power price (€/MWh)
EUA price (€/t)
MIBGas price (€/MWh)
Coal Price ($/Tn)
Gas efficiency: 52%
Coal efficiency: 38%
Gas vs. Coal Price (€/MWh)
Gas efficiency: 52%
Coal efficiency: 38%
