Europe is installing wind turbines and solar panels at an unprecedented pace, but its electricity network dates in part to the 1970s. At least 120 GW of planned renewable projects risk delays due to lack of transmission lines to carry the electricity produced, with 66 percent corresponding to a subset of transport projects in reporting countries. The late commitment of major priority lines risks limiting their contribution to emissions reduction and postponing network benefits.
The essentials
- Transmission network constraints rank among the main challenges of Europe’s energy transition, alongside equipment costs and the complexity of authorization procedures.
- The total deficit identified by Ember stands at 120 GW across 20 countries; the 66 percent represents the share of 158 GW planned in reporting countries exposed to transmission constraints.
- Redispatch costs could reach approximately 26 billion euros in 2030 in the status quo scenario of the JRC, according to European Commission estimates.
- Negative prices on spot markets are multiplying during solar and wind peaks, a sign that produced electricity cannot flow where it is consumed.
- If modernization investments are not committed before 2027-2028, construction timelines make operation before 2035 difficult.
Europe’s electricity network was not designed for what Europe is asking of it
Europe’s electricity transmission network was conceived to carry energy from large thermal or nuclear power plants, located near industrial centers, to consumers. This architecture is stable, predictable, centralized. Renewable energy works backwards: it is produced where the wind blows and the sun shines, often far from consumption centers, and in a variable manner. The North Sea region concentrates Europe’s best wind resources. Southern Spain and the Maghreb, the best solar resources.
Berlin, Paris and Milan are elsewhere.
This geographic mismatch has reached an unprecedented scale. For decades, renewables represented a marginal share of the energy mix. Today, during certain peaks in solar production, Germany, Spain or Nordic countries produce more electricity than they can consume locally or export. The surplus drives prices down to negative on spot markets, and grid managers are forced to shut down installations in perfect working order. This is called curtailment: clean electricity produced and then wasted, because the lines won’t let it through.
This phenomenon is no longer anecdotal. Episodes of negative prices are multiplying on European markets, notably in Germany and Spain, each time solar production peaks in mid-day. They signal a structural imbalance, not a cyclical one.
120 GW waiting, 25 billion in invisible costs
The data from Ember’s analysis is striking: At least 120 GW of planned renewable projects in Europe risk delays due to available network capacity constraints. The European Commission includes this in its network diagnosis. The 66 percent represents the share of 158 GW planned in reporting countries exposed to transmission constraints. To put this in perspective: 120 GW is roughly the total installed capacity of France’s entire nuclear fleet, multiplied by two.
These projects are not blocked by lack of funding or investors. Private capital is there. The technologies work. What is missing is the physical connection to the transmission network. Promoters of wind or solar farms file connection requests, wait years for a response, and see their projects postponed indefinitely.
In some countries, wait times to obtain a connection exceed seven years.
Redispatch costs could reach approximately 26 billion euros in 2030 in the status quo scenario, according to European Commission JRC estimates. This figure deserves concrete translation: congestion costs are the sums that grid managers pay to rebalance a system that cannot circulate electricity where it is demanded. These costs are passed on in transmission tariffs, then in bills. Every European household and business pays a fraction of this inefficiency without knowing it.
A queue that betrays a governance crisis
The connection problem is not merely technical. It is administrative and political. A transmission line takes on average about ten years total, including about 3.3 years of construction and the rest in planning and authorization procedures. The ten-year transmission network published by ENTSO-E, the association of European grid managers, regularly identifies priority projects. But identification is not enough: each line crosses several countries, several regions, several municipalities, each with distinct appeal rights.
The result: projects judged priority at the European level for ten years are still in the authorization phase. Operational offshore wind farms await their connection. Iberian solar corridors capable of supplying part of central Europe remain disconnected for lack of a high-capacity line crossing the Pyrenees.
Private investors do not build high-voltage lines because electricity transmission is a regulated natural monopoly: a transmission network is not competitive by definition. Its construction and financing fall to national grid managers, supervised by regulators who set tariffs and authorized investment volumes. When these envelopes are undersized or authorization procedures last a decade, no private capital can compensate.
The question of transition infrastructure financing here joins institutional capacity issues that the Journal has already documented elsewhere: a state that cannot plan and execute its long-term investments loses the capacity to steer major transitions.
Countries that advance and mechanisms that work
The picture is not uniform. Some countries understood earlier that the network was the true lever of transition and acted accordingly.
Denmark has pursued a network modernization program for its offshore operations for several years, directly linked to its wind ambitions. Energinet, the Danish grid manager, has developed accelerated authorization procedures for priority connections, with a single window and legally binding timelines. The result is visible: Denmark today has one of Europe’s highest renewable integration rates, with production episodes covering 100 percent of demand increasingly frequent.
Spain launched an authorization simplification plan in 2023 for renewable projects and their connections, reducing certain timelines from seven years to less than two years for projects deemed priority. Implementation remains uneven by region, but the direction is set.
At the European level, the Commission has included provisions in its energy package to shorten authorization timelines. The revised 2023 renewable energy directive sets a maximum two-year deadline for projects outside acceleration zones, with specific regimes in acceleration zones and exceptions for offshore. Application of this regulation remains to be monitored: several member states struggle to adapt their national procedures within the given timelines.
ENTSO-E estimates over 400 billion euros in investments required for offshore transmission by 2050. Only a portion of these amounts is currently committed or planned. The gap is colossal.
2027 decisions condition 2035 results
The window for action is narrow. A transmission line takes on average about ten years from investment decision to commissioning. If major priority transmission lines are not committed before 2027-2028, their effects will not arrive until after 2037-2040, which risks limiting their contribution to reaching 2030 climate targets and will push network benefits beyond 2035. The network bottleneck can thus become a de facto irreversibility, because the time to overcome it exceeds available time.
Two trajectories are open, and the coming years will decide which one Europe takes.
In the first, a structured public-private partnership could mobilize necessary investments before 2030. National grid managers can benefit from increased investment envelopes according to their regulators’ decisions. Cross-border projects with PCI or PMI status fall under the TEN-E framework. For these projects, national regulatory authorities can adopt cross-border cost allocation decisions, and project sponsors can seek financing under the Connecting Europe Facility.
The TEN-E regulation provides streamlined authorization procedures lasting three and a half years, with possible exceptional extension of nine months. In this scenario, renewable capacity at risk would gradually be connected and congestion costs would remain manageable.
In the second scenario, delays accumulate. Congestion costs increase significantly. Abundant and cheap renewable electricity becomes accessible in well-connected zones, but remains out of reach for poorly served territories. The transition fragments geographically: some regions benefit from competitive decarbonized electricity, others remain dependent on carbon sources due to lack of physical network access. This scenario manifests through accumulated delays, postponements and abandoned projects.
But it produces a lasting fracture between territories included in the transition and those excluded by their location.
This geographic fragmentation of transition benefits has precedents. Comparable mechanisms exist in access to strategic resources: value added concentrates where infrastructure exists, not where resources are produced.
Signals to follow
Two indicators allow us to know which of the two trajectories Europe is actually taking, beyond announcements.
The first: the number of GW of renewables actually connected each year, compared to the objectives of the ENTSO-E Ten-Year Plan. If the gap widens, the fragmentation scenario is materializing. If the gap narrows, administrative reforms and investments are producing results.
The second: the frequency and annual cost of negative price episodes on European spot markets, published annually by Ember Energy. These negative prices are the network’s thermometer. When they increase in frequency and duration, the network is not absorbing renewable production. When they decline, the lines are working.
The political question underlying all of this is one of cost-sharing. Congestion costs are currently mutualized de facto in transmission tariffs, but in an opaque and unequal manner. Poorly connected territories pay for the imbalances produced by better-equipped neighbors. An explicit equalization mechanism, discussed in several Commission proposals, would at least make this transfer visible and negotiable, rather than imposed.
The creation of a European transmission network planning and financing agency, with its own borrowing capacity on capital markets, is today one of the most serious options on the table. It would solve the structural problem of cross-border corridors: these lines are collectively profitable for Europe, but no state has an incentive to finance them alone, because the benefits spill across its borders. This is the classic case where the market cannot do what public coordination can do. ENTSO-E plays a coordination and planning role, but without binding mandate or its own financing capacity.
Europe has achieved mobilizations of this type in other areas when pressure was sufficient. Electricity network connection is less visible than solar panels on rooftops or offshore wind turbines. That is precisely why it risks being addressed too late.
Sources
- TEPSA / Ember Energy / European Commission, Europe’s Energy Security in 2026: More Resilient but Systematically Exposed: https://tepsa.eu/analysis/europes-energy-security-in-2026-more-resilient-but-systematically-exposed/
- ENTSO-E, Ten-Year Network Development Plan (TYNDP): ten-year planning document for Europe’s electricity transmission network (no link: stable page to consult on entso-e.eu)
- European Commission, Renewable Energy Regulation (2023 revision), provisions on authorization timelines
- Ember Energy, Annual data on negative prices and congestion episodes on European spot markets (no link: annual reports available on ember-climate.org)
