Europe can unlock 25 GW of wind and solar capacity by siting new generation at existing hydropower plants across seven EU member states, according to a new report from the energy think tank Ember – and it requires zero new grid infrastructure. That matters because the single biggest bottleneck slowing Europe’s energy transition right now is not a lack of renewable projects, but a lack of available connection points; co-locating generation where substations and grid capacity already exist is one of the fastest, cheapest ways to put that stranded power online before the end of the decade.
Why Existing Hydropower Sites Are the Fastest Fix for a Grid-Bound Clean Energy System
The core mechanism is simple: a hydropower plant already has a connection to the high-voltage grid, a substation, transformers, and often significant land holdings around its reservoirs and penstocks. Installing solar panels or wind turbines inside that existing footprint lets the new generation share the same grid connection, with the hydro plant’s output and the new renewable output managed against the capacity limit already in place.
The context for why this matters is the connection queue crisis. Across Europe, project developers are waiting years for grid connection agreements, and the backlog of permitted clean energy projects waiting to connect is now measured in hundreds of gigawatts – far more than the continent’s current build-out pace requires. For a standalone solar farm, the queue alone can delay a project by four to seven years, depending on the market. Co-location at a hydro site sidesteps that entirely: the connection exists, the land is often already zoned for energy use, and environmental impacts are already understood.
Hydropower also has a second, less obvious advantage: flexibility. A reservoir or run-of-river plant can adjust its output to accommodate the variable generation of co-located wind and solar. When the sun is strong but demand is low, the hydro plant can ramp down, freeing the shared connection capacity for the solar array. That makes the hybrid plant as a whole a more predictable, more dispatchable resource than either technology alone – which is precisely what grid operators need as thermal baseload plants retire.
The 25 GW figure is not trivial. It is on the order of, for example, roughly the entire current installed capacity of a large national market like the Netherlands, or roughly a fifth of the wind capacity Europe added over the past five years. If this trend holds and the seven-country analysis becomes a template, the actual ceiling is likely higher: the report scopes only EU member states, but Norway, Switzerland, and other European Economic Area countries with substantial hydro fleets sit outside that perimeter.
Why Hybrid Grid Connections Are Reshaping the Economics of European Renewables
This development belongs to a broader shift in how grid capacity is being created – not by building more line, but by using existing connections more intelligently. Across Europe, grid operators are increasingly experimenting with “hybrid” connection models, where multiple generation assets share a single point of connection, and with dynamic line ratings that let operators push more current through existing cables when weather conditions allow.
The economic logic is overwhelming. A brand-new high-voltage connection to a remote rural location can cost on the order of tens of millions of euros and take close to a decade to permit and build. Co-locating at a hydro site avoids nearly all of that capital and schedule risk. The cost of adding solar to a hydro plant’s substation is typically a fraction of the cost of a new grid tie-in – the two biggest line items, the transformer and the connection agreement, are already in place. By comparison, every gigawatt of new generation that connects through an old hydro asset is a gigawatt of capacity that does not require a new tower, a new conductor, or a new substation anywhere.
There is a parallel to the rapid rise of battery energy storage co-located with solar: project developers figured out that sharing a connection point and one set of balance-of-plant equipment improved project economics even before grid constraints forced the issue. The Ember analysis suggests the same logic applies at the level of large hydro infrastructure. If this trend holds, the next step is natural – a three-way hybrid where wind, solar, and battery storage all share the hydro connection, using the hydro’s existing reservoir as a form of seasonal storage and the battery as a short-term buffer.
That evolution raises a policy question the report implicitly highlights: how do grid tariffs treat a connection that was originally sized for one generator but now carries several? If the answer is that the shared connection pays one set of fees for one capacity level, then co-location becomes a subsidy to the new entrant. If the answer is that each technology pays separately, much of the economic advantage evaporates. How the seven member states resolve this will determine whether 25 GW is a floor or a ceiling.
One more implication matters for system planning. Hydro plants tend to sit in mountainous regions where the local grid is often weak and winter demand is driven by electric heating. Adding 25 GW of wind and solar at exactly those locations could in some cases overload the same local lines that the connection point feeds – the substation has capacity, but the surrounding network may not. The report’s headline is about grid connections, but the real constraint may end up being local distribution and transmission reinforcement just a few kilometres beyond the plant gate.
Who Gains Most from the 25 GW Hydro Co-Location Opportunity
- Wind and solar developers: Treat hydro sites as a priority acquisition target. Existing owners of hydro concessions and their surrounding land parcels are the most direct route to a grid connection that is already permitted – a partnership or lease at a hydro site can cut your development timeline from years to months.
- Transmission and distribution system operators: Expect to receive hybrid connection requests for hydro sites in your control area. Start publishing clear rules now for how shared connections are managed, how capacity is allocated during congestion, and whether curtailment priority sits with the incumbent hydro or the new renewable entrant.
- Hybrid plant designers and storage vendors: The integration challenge is real: designing a control system that coordinates hydro output, solar intermittency, and potential battery storage against a single export limit is a new engineering problem. The market for that control software and hardware will grow in proportion to co-location uptake.
- Utilities and asset owners of hydro fleets: Your existing reservoirs and substations have a balance-sheet value beyond electricity generation. Selling grid access or leasing land for co-located renewables turns a mature asset into a platform business – but the revenue model and risk allocation for “shared grid capacity” must be nailed down before you sign.
What to Watch Next in Hybrid Hydro and Clean Energy Co-Location
- The full Ember report, once released, will name the seven member states and their individual capacity breakdowns – watch for countries like France, Spain, Austria, and the Nordic states, whose hydro fleets are large enough to offer double-digit gigawatt potential on their own.
- National regulatory revisions to grid connection rules over the next 12 to 18 months: any change that explicitly allows a second generator to share an existing connection without a full new application will accelerate the 25 GW opportunity, while any tariff penalty for hybrid connections will slow it.
- Whether any of the seven countries launches a joint tender or a dedicated auction for co-located hydro-renewable capacity – a policy signal that would convert a paper potential into a pipeline of actual projects.
- Capacity market design across the EU: if co-located hydro-plus-solar is treated as a firmer, more dispatchable resource than standalone solar, it could earn credit as de facto storage capacity, changing the value proposition for investors.
Bottom Line
The 25 GW that Ember identifies is not a forecast of what will be built – it is a measurement of what is already possible using assets Europe owns and has already paid for. For a continent facing years-long connection queues and a race against its own decarbonisation deadlines, the cheapest new clean power is the power that can plug into a grid connection that already exists. That is a policy problem, a commercial opportunity, and an engineering challenge all at once – and it is now quantified for the first time.
Read the full report at CleanTechnica.
Note: facts and figures attributed above to reflect that outlet's original reporting. Broader context, cross-sector connections, and forward-looking scenarios reflect independent analysis by our editorial team.
About this article: Drafted by Energy Ai with AI-assisted research and writing based on public reporting, then reviewed under our editorial process before publication.
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