Why Italy Pays Europe’s Highest Power Prices — And Why Diversification Hasn’t Helped

Italy's electricity problem is not that it buys expensive gas. It is that the price of gas decides the price of everything.

Under the marginal pricing design used across European power markets, the most expensive generator needed to meet demand in any given hour sets the price paid to all of them. Gas accounts for only 18–20% of EU electricity generation but disproportionately drives power costs because of that design, according to analysis by IEEFA. When the Dutch TTF benchmark spikes, day-ahead electricity in gas-reliant markets such as Italy and Germany reaches €120–150/MWh, while countries with more diverse mixes — France and the Iberian markets — stay closer to €60–80/MWh.

Italy sits at the wrong end of that split for a structural reason. Gas remains central to the Italian system, accounting for close to half of generation and setting the marginal price for a much larger share of hours than in neighbouring markets. France's nuclear fleet and Spain's renewables displace gas from the margin for long stretches of the day. Italy's do not.

The consequence is a persistent premium rather than an occasional spike. Italian day-ahead prices have been running well above the northern European range this summer: the average across Italy's bidding zones was around €143/MWh on 7 July, with the day-ahead price near €147/MWh, on ENTSO-E data.

Diversification reduced the dependency, not the exposure

The standard European answer to energy risk since 2022 has been to replace Russian pipeline gas. Italy and the EU did exactly that, and the price problem did not go away.

Russia fell from around 45% of EU gas imports in 2021 to roughly 12% in 2025, replaced largely by LNG, which now accounts for about 48% of EU imports. But diversifying suppliers did not reduce exposure to gas price volatility. It changed its source. European prices are now tied closely to a global LNG market shaped by Asian demand and Middle Eastern supply — which is why a shipping crisis several thousand kilometres away transmits directly into Italian tariffs.

The mechanism is visible in the current market. Qatari cargoes constrained by the Strait of Hormuz push Asian buyers to compete for Atlantic-basin volumes that Europe also needs, and the resulting price is what Italian gas-fired plants pay before they set the marginal price for Italian electricity. Even without physical disruption, IEEFA notes, the risk premium embedded in gas markets can move power prices significantly.

That premium is currently being reset upward by events Italy has no influence over. Shipping through the strait remains far below normal levels, with the UAE reporting that two of its tankers were attacked while attempting the crossing, and analysts warning that a prolonged closure carries the risk of substantially higher crude prices.

The zonal complication

Italy has one feature that makes its power market unlike any other major European system: it does not have a single price.

The grid is divided into six bidding zones — North, Centre-North, Centre-South, South, Sicily and Sardinia — each clearing separately, a structure that exists because limited internal transmission and congested corridors prevent cheap southern generation from reaching northern demand. The divergence can be extreme. A solar peak in Sicily can leave that zone clearing near €30/MWh in the same hour the North pays around €120/MWh.

Market operator GME calculates the PUN Index GME, the reference index for the day-ahead market, as a weighted average of those zonal prices. It replaced the old single national price from 1 January 2025 under a ministerial decree issued in April 2024, and it accounts for both volumes sold and time-of-use periods.

For consumers the distinction is not academic. Most variable-price retail contracts reference the PUN, but a household's actual cost depends on its zone and contract type, with the final bill adding retailer margin, grid charges, system charges and VAT on top of the wholesale reference. Households in the South and Sicily on zonally indexed contracts can pay less during high solar output. Northern households, closer to industrial demand, often do not.

Italy is also midway through changing the rules. The dispatching framework known as TIDE entered its consolidation phase on 1 February 2026 and runs to 2028, and the balancing timeframe has been shortened from hourly to 15-minute intervals to integrate variable renewables and align with European practice. Market participants have suggested the shorter interval makes negative prices more likely and will widen the gap between midday and evening periods — which, in a country with Italy's solar profile, is a meaningful structural change rather than a technical footnote.

The transition is not moving fast enough to help

The obvious long-term fix is to take gas off the margin more often. Italy is not doing that quickly.

According to ENEA's assessment of 2025, the cost of energy in Italy remained at record levels, with gas around 70% and electricity around 100% above the pre-crisis 2022 baseline, while renewables grew by just 1% and remain roughly 20% short of the National Integrated Energy and Climate Plan targets. ENEA's Ispred index, which tracks energy system performance, fell 30%, with the sharpest problems on decarbonisation.

The import bill compounds it. ENEA estimated that in March alone the cost of gas imported by Italy could exceed €2 billion, an extra cost of at least €500 million against the annual average.

What to watch

The near-term variable is the strait. Italy's electricity prices will track global LNG for as long as gas sets the margin, and gas will set the margin for as long as the generation mix stays where it is.

The medium-term variable is domestic and more within Italy's control: how quickly renewable capacity closes the roughly 20-point gap to plan, and whether the TIDE reforms and zonal signals actually shift where and when power is generated. Neither will change this winter's bills.