According to the European Court of Auditors, Europe’s electricity system needs about two trillion euros in grid investments by 2050. But even if every country builds as fast as it can, the physics of digging, permitting, and stringing wire move slower than the energy transition demands. To get closer to the core of this challenge, we can look at a single transmission line in northern Germany.
In a recent Cleaning Up episode, TenneT COO Tim Meyerjürgens shared the economics of a 60 km line built just south of Bremen that cost €1 billion. At first glance, that’s steep. But in its first year of operation, the line saved €500 million in redispatch costs. In other words, it pays for itself in only two years.
That’s a strong return - until you consider the timeline: the project took 20 years, with 17 spent in permitting.
Obviously, Europe doesn’t have 20 years to solve its grid bottlenecks. TenneT Germany alone plans to invest €65 billion over the next few years to meet grid buildout targets. The physical need is clear - but the delivery speed is not. This creates a massive tension between the physics of the grid (we need wires) and the reality of time (we can’t build them fast enough).
We’re essentially facing three strategic pathways.
Scenario 1: Full interconnection
A fully coupled European market - this has been the current dominant strategy: build massive interconnectors and couple every market tightly, aiming for a "copper plate" where electricity flows frictionlessly across the continent.
The benefits are real: ACER estimates that cross-border trade saves European consumers €34 billion annually, as lower average prices flatten price differences. However, the math is breaking down. We rely on algorithms like EUPHEMIA to clear these complex markets, but they have become opaque "black boxes" that sometimes produce counter-intuitive flows.
Relying only on physical coupling creates new vulnerabilities. When highly distinct markets are coupled, they don’t just trade surplus power - they also share volatility.
- In Norway, the opening of NordLink and North Sea Link to Germany and the UK caused sharp domestic price increases. While these cables unlocked export opportunities, they also exposed hydro-rich southern Norway to neighbors’ gas-driven price spikes - triggering political pushback and concerns over energy affordability.
- In balancing markets, platforms like PICASSO (for aFRR) were designed to improve system efficiency. Yet in 2024, Italian TSO Terna paused participation due to price swings caused by algorithmic activation, and other countries are seeing similar effects - showing that without tailored safeguards, cross-border automation can create more instability than it resolves.
In short, the “copper plate” model may reduce structural costs, but it also raises operational risks unless local flexibility is part of the equation.
Scenario 2: Back to fragmentation
We could also go back to how things worked 30 years ago: isolated national markets with limited interconnection, where you prioritize national self-sufficiency and avoid importing your neighbor’s volatility. However, this scenario creates massive inefficiencies.
In a renewable-heavy system, "autarky" means one country drowns in excess wind power (negative prices) while its neighbor burns expensive gas to meet peak demand. To make this work, every nation would need to build redundant backup capacity, driving system costs to astronomical levels.
Scenario 3: Flexing a smarter mix
We can start treating flexibility as a primary grid asset, build only the wires we need, and stop pretending that copper is the only answer.
This is where the math shifts. If a transmission line takes 20 years to build, software-defined flexibility takes months to deploy. A study by DNV for SmartEn found that fully activating demand-side flexibility could save the EU €29.1 billion annually in grid investments.
What we mean by "Flex" clearly goes beyond just installing batteries. It is the software layer that sits between the asset and the market:
- Virtual Power Plants (VPPs) that aggregate and dispatch across portfolios
- Smart redispatch using demand-side resources
- Sub-second market reactions via algorithmic trading
- Load shifting to avoid congestion and reduce the need for costly curtailment
These tools can be deployed in months, not decades. They also scale faster and adapt more easily to changing system needs.
Meanwhile, the one type of hardware that significantly contributes to flexibility - batteries - is being held back by another type of inflexibility. Under current grid rules, Germany faces a backlog of 250 GW in battery connection requests - three times its peak load. The “first come, first served” model is becoming a bottleneck.
What’s needed is a shift to system-relevant prioritization: assets should be integrated based on their value to the system, not their position in a queue. That’s where flexibility-first planning begins to matter.
Planning with 2045 in Mind
Traditional grid planning operates on a 10-year network development plan (TYNDP by ENTSO-E). That no longer works. Germany’s energy goals extend to 2045 - and current extrapolations won’t get us there. As TenneT now argues, we need to start with the endpoint and work backward.
In that view, flexibility doesn’t compete with transmission - it extends its utility. It reduces redispatch, keeps prices stable, and buys time for critical infrastructure to be built. A 20-year asset can deliver long-term benefits, but a 2-month flex deployment can solve today’s problems.
We’ll still need new wires. But if Europe waits for copper alone to carry the transition, it will run out of time. The right approach is straightforward: build what’s necessary, but make full use of digital flexibility in the meantime.
Wires without flex create risk. Flex without wires has limits. But together, they’re how Europe keeps the lights on - affordably, securely, and on schedule.
