European Commission underestimates gas demand impact from Iberian-style price cap – ICIS modelling

Matthew Jones


LONDON (ICIS)–The introduction of an Iberian-style price cap on gas used for power generation could increase EU gas demand by 6.5-12.2 bcm in 2023, our modelling shows.

This is above the recent estimate from the European Commission of an impact of between 5-9bcm. The discrepancy is largely driven by an increase in fuel switch from coal back to gas at a lower gas price cap of €100/MWh.

In this analyst update we model the proposed Iberian-style gas price cap and give our view of its potential implementation.


EU member states have approved a cap on inframarginal generators between December and June, with the revenues generated used to help reduce electricity costs for consumers. We recently estimated that the cap would raise a maximum of €57bn during its seven months of implementation.

However, the European Commission also recently assessed the impact of an Iberian-style price cap on gas used for power generation. While the timeline for implementation was unclear, they suggested that the cap price could be in a range of €100-€120/MWh.

The EU is also looking at longer-term ways to intervene in European markets, recently laying out a vague idea for a market split between firm and non-firm power.

Modelling approach

We ran our model for the years 2023-2024 with gas price caps of €100/MWh and €120/MWh, and compared the results of each scenario to our Q3 Base Case (which itself is based on fuel prices from 12 September).

We kept carbon and coal prices constant to our Q3 Base Case.

We assumed that the price cap was only in place for EU countries so we could assess the impact on cross-border flows to non-EU countries.

Power prices

The extent of the price decline depends on the level of the cap and the expected TTF forward price in a given year.

For 2023, the cap at €100/MWh has a significant power price impact, lowering average EU prices by 21%. However, with a cap at €120/MWh the price decline is only 14% on average.

For 2024, the cap at €100/MWh leads to a 5% price decline on average, but has no impact in the €120/MWh scenario as the cap is above the TTF price.

While the GB market does not have a cap in place, it still leads to a price decline of either 6% (€100/MWh) or 4% (€120/MWh) in 2023 because of the impact of lowering prices in connected markets and encouraging exports to GB.

Gas demand and fuel switch

Our modelling suggests that EU gas demand would increase by between 6.5 and 12.2 bcm in 2023 depending on which of the two gas cap prices was to be adopted. This is slightly higher than the figure of 5-9 bcm from the Commission’s own modelling.

The Commission suggests that their increase is mainly due to higher exports to non-EU countries (rather than fuel switch). However, our modelling suggests that the share depends upon the cap price.

At a cap of €120/MWh fuel switch makes up 35% of the 6.5bcm increase in gas demand in 2023 (65% due to increased flows to non-EU countries).

However, at the lower gas cap of €100/MWh, fuel switch makes up 60% of the 12.2bcm increase in gas demand (with the remaining 40% due to increased flows).

The results highlight the fact that the lower the gas cap is in relation to the TTF price, the more likelihood there is of fuel switch away from coal and back to gas.

The annual five-year average of EU gas demand is 398bcm, suggesting that in a scenario where gas is not already being saved, a 6.5bcm rise would equate to an increase of 1.6% in gas consumption. An extra 12.2bcm used would lead to a 3.1% gain.

But given the high TTF price, mild-weather and policy-led switching, gas demand in October was 24% below the five-year average. In September it was almost 14% below the average. The EU is calling on member states to achieve a 15% reduction through to the end of March.

Assuming the 15% target was hit without the introduction of the inframarginal generator cap and continued through all of next year, EU demand would be closer to 338bcm in 2023. If this was the case an extra 6.5bcm of gas-to-power would then raise demand by 1.9%, with it increasing to 3.6% should 12.2bcm be additionally used.

In effect – where the EU’s 15% gas demand reduction target is extended over all of 2023 – the then introduction of the Iberian-style price cap negates 1.5-3.1 percentage points of that 15% reduction. In other words, around a fifth of the EU’s 15% demand reduction target, when applied to 2023, could be reversed by the power-market policy.

Impact on carbon prices

As noted above, we kept carbon prices constant for the model run. However, there would be competing drivers on EUA prices as fuel switch back to gas is a bearish driver on emissions, while the increase in net flows is bullish.

In the €100/MWh cap scenario, which has a lot of fuel switch, we see negative overall power emissions impact in the EU in 2023 (-1.5%) whereas in the €120/MWh scenario emissions increase slightly by 0.5%.

The impact on UKA prices is bearish in either scenario as the cap reduces power prices in EU countries and therefore encourages a reduction in GB gas-fired generation at the expense of imports from EU countries.

Uneven distribution of costs

As we outlined in the previous story, the gas price cap would have an uneven cost distribution as the countries with the highest levels of gas-fired generation would face high levels of subsidy and vice versa for countries with low levels of gas-fired output.

Our figures suggest that Italy, Germany, and the Netherlands combined will account for 56% of the EU’s gas-fired generation in 2023. Italy alone accounts for 30% of the figure.

As the Commission admitted in their analysis, a system to redistribute the costs effectively would be required, but would also likely be difficult to set up for political and accounting reasons.

ICIS view

As we stated in the previous story, non-papers by the Commission are worth following closely at the moment given the examples of them being turned quickly into official policy. The Commission appears to be pushing the Iberian price cap policy, though its own analysis presented a mixed view of the impact.

Our modelling suggests that the Commission has underestimated the potential for the policy to increase gas demand in the EU, though the impact is highly sensitive to the cap price in relation to the TTF price.

The Commission suggests that unlike with the Iberian cap, coal should be excluded for an EU cap. Presumably this is due to a desire not to subsidise coal plants in the EU to operate. However, our modelling shows that this has potential to lead to fuel switch from coal back to gas in the EU. The amount of fuel switch is highly dependent on the level of the cap in relation to the TTF price.

If the cap is set significantly below the TTF price then significant fuel switch is seen. But if the cap is close to the TTF price then the measure has almost no impact on reducing power prices.

A cap price of €100/MWh in 2023 leads to a lot of fuel switch and therefore increased gas demand, while a cap price of €120/MWh in 2024 would have no impact at all.

The cost distribution would be significantly uneven given the disparity in gas-fired generation in the EU 27. Three countries account for 56% of the total generation and would therefore pay disproportionate costs in the absence of a redistribution mechanism, which the Commission itself says would be difficult to implement.

The Commission also states that non-EU countries like the UK should join the system to make it most effective and avoid increasing net flows out of the EU. However, as the second largest gas generator in Europe behind Italy it is not clear why the UK would want to join such a scheme.

In our view, the EU already has a way to protect consumers from high prices through the inframarginal cap. It seems odd to be looking for a second way to temporarily intervene in the market, especially since the Iberian price cap method would undermine the impact of the inframarginal cap (by lowering wholesale prices and therefore the revenues taken in) while having the negative consequences of increasing gas demand and being hard to administer equally and effectively.


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