13APR

Power prices split EUR 131 north-south

3 min read

22:33UTC

Italy cleared at EUR 133/MWh while Spain paid EUR 29/MWh on the same day, the starkest intra-EU power price divergence of 2026.

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Key takeaway

Gas sets the power price 90% of the time in Italy and 15% in Spain, producing a EUR 100+ spread.

Italy cleared at EUR 133/MWh in day-ahead power on 13 April 2026, while Spain settled at EUR 29/MWh on the same exchange day. The Netherlands matched Italy at EUR 128/MWh, Belgium at EUR 128/MWh. France surged 188% day-on-day. Then south and north: Spain at EUR 29/MWh, Portugal at EUR 28/MWh, Norway (northern zones) at EUR 2/MWh. A single market, five time zones apart in price.

Merit order mechanics explain the gap. In gas-dependent markets, gas-fired plants set the marginal clearing price. Ember data shows gas sets the electricity price most hours in Italy but a fraction of that in Spain, where wind and solar capacity has displaced gas from the stack. The result: a EUR 100+/MWh spread between Iberian and north-western European power markets.

For industrial consumers, the spread is a location arbitrage signal. Energy-intensive production in Spain operates at roughly one quarter of the power cost of an equivalent plant in Italy or the Netherlands. For policymakers, it is a live demonstration that renewables penetration translates directly into price shock insulation, not in theory or over a decade, but on a single trading day.

Deep Analysis

In plain English

Electricity prices in Europe vary by country because each national grid has a different energy mix. Countries that generate most of their power from wind, solar, and hydropower pay less when gas prices are high, because gas is not the primary source setting their prices. On 13 April, the gap between Italy (EUR 133/MWh) and Spain (EUR 29/MWh) showed this vividly. Italy relies heavily on gas-fired power stations, so when gas is expensive, Italian electricity is expensive too. Spain has invested heavily in wind and solar, so gas prices matter much less to Spanish electricity costs.

Deep Analysis

Root Causes

The Italy-Spain divergence reflects two decades of unequal investment in power system gas dependency. Italy built approximately 40 GW of gas-fired combined-cycle capacity between 1995 and 2010, primarily because gas was cheap and nuclear was politically blocked after the 1987 referendum. Spain, facing similar nuclear constraints, pivoted to wind and solar from 2005 onwards, accelerated by EU renewable energy directives.

The result is that Italian power dispatch depends on gas as the marginal clearing technology for approximately 90% of hours, while Spanish dispatch has largely moved gas to the peaking residual. This was a strategically advantageous position in 2015-20 when TTF was EUR 15-20/MWh; it is now a structural liability at EUR 47/MWh.

Escalation

The 188% France day-on-day surge is the most acute indicator: France, normally insulated by nuclear baseload, apparently lost significant nuclear generation on 13 April (likely a combination of planned outages and load constraints), exposing its residual gas dependency. If French nuclear availability remains below seasonal norms through April, French prices will continue to trade closer to the Dutch-Belgian range than the Spanish.

What could happen next?

Consequence
Energy-intensive industrial production is shifting toward Iberia at an accelerating rate, creating a structural permanent loss of manufacturing activity in Germany, Italy, and Belgium that will not reverse even if gas prices normalise.
Opportunity
The Pyrenean interconnector expansion, currently in ENTSO-E planning phases, has gained urgent political support from both French and Spanish governments as the EUR 100+ price gap makes the economic case undeniable.

Source Landscape

This story draws on neutral-leaning sources

Primary parallel: In February 2021, the Texas freeze produced a similar extreme divergence within a single power grid: ERCOT prices spiked to USD 9,000/MWh while neighbouring MISO prices stayed below USD 100/MWh, because interconnector limits prevented arbitrage. The EU situation is less extreme but structurally identical: physical limits prevent price equalisation even when the economic incentive is enormous.

Counter-parallel: In 2014-15, Nordic-Continental European price divergence reached EUR 30-40/MWh due to Norwegian hydro constraints, but the NordLink and Viking Link subsea cable projects eventually closed most of the gap. The Pyrenean situation is structurally harder to resolve because mountain terrain makes additional interconnector construction significantly more expensive than the North Sea subsea cables.

The EUR 104/MWh spread between Italian and Spanish day-ahead prices on 13 April represents the single-day economic value of Spain's renewables investment at current gas prices. Aggregated across Italy's approximately 350 TWh of annual electricity consumption and the proportion that clears at marginal gas prices, a sustained EUR 100/MWh differential would add approximately EUR 35 billion to Italy's annualised electricity cost relative to an equivalent-sized Spanish economy.

For industrial consumers with cross-border operations, the differential creates direct locational investment incentives: energy-intensive manufacturers are accelerating shifts of production capacity toward Iberia, where real electricity prices are four to five times lower than in northern Italy or Belgium. This is a structural industrial policy outcome, not a temporary market signal.

Consensus view: ENTSO-E market analysis group assessed that the EUR 100+ divergence between Iberian and north-western European day-ahead prices confirms a structural failure of cross-border interconnection: the Pyrenean interconnector capacity (approximately 3.4 GW) is too small to arbitrage the gap, and ENTSO-E's own Ten-Year Network Development Plan identified this as a tier-one constraint as long ago as 2019, with the French-Spanish cross-border upgrade not expected before 2029.

Counter-view: The Spanish Red Electrica argued that the Iberian price isolation is two-directional: Spain's low prices under current conditions benefit Iberian consumers, but the same interconnector constraints that prevent Spanish renewables from suppressing north-western European prices also prevent Spanish consumers from accessing cheaper Norwegian hydro or French nuclear in periods of Iberian drought. The Pyrenean barrier is not purely a north-western European problem.

Key tension: Whether the EU internal energy market framework, which assumes price convergence as the measure of integration success, is still the right metric when structural interconnector deficits mean divergence is not a market failure but a physical constraint.

Sources:Ember

Mentions:Italy →Russia →Netherlands →Belgium →France →Portugal →Norway →Ember →Prima →Texas →

First Reported In

Update #1 · Europe's thinnest gas cushion since 2018

Ember· 13 Apr 2026

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Causes and effects

This Event

Power prices split EUR 131 north-south

The EUR 100+ spread between gas-dependent and renewables-rich markets quantifies the structural value of energy mix diversification under a gas supply shock.

Led to

Italy-Spain spread compresses 76% in four sessions

The EUR 104 Italy-Spain spread on 13 April was the opening level that subsequent four-day compression reversed to EUR 24.54.

Occurred 17 Apr 2026

Read story →

Spain power jumps 148% in two days on low wind

Spain's 148% surge on 15 April is the opposite extreme from the EUR 29/MWh low on 13 April, demonstrating the volatility underlying the Iberian insulation thesis.

Occurred 15 Apr 2026

Read story →

Different Perspectives

Amsterdam-Rotterdam gas trading desks

TTF failing to sustain EUR 47+ with 51 mcm/day of Norwegian capacity offline confirms EUR 50 as a diplomatic ceiling; the curve is a Troll-restart long, and EBN's EUR 233 million mandate budget cap is a known limit on price-insensitive prompt buying.

ARERA

Italy's energy regulator is running mandatory storage injection that carries the EU aggregate trajectory alongside CRE and EBN, while Italian industrial consumers at Panigaglia face a simultaneously low-utilisation terminal and a EUR 2/MWh delivered-cost basis above TTF. The mandate funds security of supply at the expense of Italian competitiveness.

Shell

As a long-term Russian LNG contract holder, Shell faces a replacement procurement problem concentrated in Q3-Q4 2026 ahead of the 1 January 2027 double cliff; with terminal booking lead times running weeks, the real deadline is late November 2026 and no replacement supply has been publicly named.

CRE

France's 100% mandatory booking order funds injection regardless of the inverted strip, providing the EU aggregate cover that Germany's abolished levy cannot; the CRE order is renewed annually, making it a political risk rather than a structural guarantee. That dependency exposes the EU injection trajectory to French electoral cycles.

Bundesnetzagentur

Germany's regulator holds the early-warning gas stage active with no statutory instrument to compel commercial injection, and Berlin confirmed on 20 May it will introduce no summer incentive scheme; Germany is the EU's only major unincentivised storage market after the levy lapsed on 1 January 2026. The mandate gap is carried by three other member states.

European Commission

The Commission relaxed the mandatory fill target from 90% to 80% and published an ETS benchmark revision saving industry EUR 4 billion, choosing industrial competitiveness over both climate and storage ambition at the moment physical margins are tightest. Both decisions reduce policy pressure at the exact week the trajectory margin narrowed to 45 GWh/day.