European Union energy ministers have agreed on the Council’s position on the European grids package, a set of legislative proposals aimed at modernising and expanding Europe’s energy infrastructure. The package includes a revision of the TEN-E Regulation on trans-European energy infrastructure and a directive to accelerate permitting for energy infrastructure.
The issue is directly linked to one of the key constraints of the energy transition: the ability of grids to accommodate new generation, storage and electrified consumption projects. In a market where renewable energy developers, battery investors, large industrial consumers and grid operators are increasingly facing questions around connection capacity, congestion and investment timelines, the European grids package may become an important part of the bankability framework.
Pan-European planning
The Council of the EU says the package is intended to improve the planning of cross-border energy infrastructure, simplify and speed up permitting procedures, and strengthen grid security and resilience. The Council’s position includes a common planning framework for the development of electricity, hydrogen and gas networks, based on a central scenario prepared by the European Commission with input from Member States and relevant stakeholders.
This planning process is expected to take into account national energy and climate plans, regional specificities and price differences between markets. For Romania, the stakes are even higher, as regional price spreads, the need for stronger interconnections and the pressure created by solar, wind and storage projects are already showing up in investment decisions and grid connection risk assessments.
A study published in March 2026 in Academia Green Energy, focusing on transfer entropy and causal price spillovers between Core and Southeast European electricity markets, offers a useful explanation of why this matters. The authors show that the Central European Core markets, operated under Flow-Based Market Coupling, form a more integrated system, with bidirectional feedback and faster price convergence, while Southeast European markets, still operating under the Net Transfer Capacity methodology, show weaker causal connectivity and slower adjustment. In other words, price differences are not merely isolated market episodes; they may reflect the coexistence of two partly decoupled operational and regulatory regimes.
This conclusion gives the European grids package both political and economic weight. If prices converge slowly not only because of a lack of cables or substations, but also because of the different ways in which cross-border capacities are calculated and made available, then physical investment must be matched by methodological harmonisation, effective application of the rule on capacity made available for cross-zonal trade, and the development of stronger cross-border flexibility. The study makes this point explicitly: lasting price convergence requires not only additional interconnection capacity, but also aligned capacity calculation methodologies, compliance with the 70% MACZT rule, and better cross-border flexibility.
New sources for investment
One important element of the Council’s position concerns the use of congestion income. Member States have agreed that part of the unspent revenues generated by grid bottlenecks between bidding zones should be reinvested in cross-border projects designed to reduce congestion. According to the Council’s position, the allocation would start at 10% from 1 January 2028 and gradually increase to 25% by 2031.
This mechanism could become important for markets such as Romania, where congestion is increasingly visible in discussions about renewable integration, BESS development and regional price differences. Congestion is no longer just a symptom of insufficient infrastructure; under certain conditions, it can also become a source of funding for projects that reduce cross-border bottlenecks.
Several episodes analysed in the previously cited study show that, in the summer of 2024, interconnected Central and Southeast European markets recorded sharp evening price spikes. On 10 July 2024, day-ahead prices were relatively aligned during the early hours of the day, before decoupling abruptly between 19:00 and 24:00. On that day, Hungary reached approximately EUR 693/MWh, Romania around EUR 442/MWh, while Austria remained below EUR 200/MWh. The study links this divergence to reduced transfer availability across several regional interfaces, including RO–BG and GR–BG, which limited spatial rebalancing during peak hours.
This is an essential point from Romania’s perspective in the context of the European grids package. Price problems cannot be explained solely by domestic generation or local demand; they also depend on the system’s ability to move electricity where it is needed, at the times when system stress is highest. In a region where solar generation compresses prices at midday while evening peaks remain expensive, interconnections, capacity allocation rules and flexibility become part of the same equation.
Faster permitting
The package also includes measures to speed up permitting. The Council supports more transparent procedures, digital portals for submitting applications and the treatment of electricity and renewable energy projects as projects of overriding public interest, unless the contrary is demonstrated. Member States may also decide that a lack of response from authorities at certain intermediate stages of the permitting process should be deemed tacit approval.
The impact of these provisions will depend on how they are transposed and applied at national level. A shorter permitting timeline can reduce administrative risk, but it does not remove the need for real technical connection solutions, investment in transmission and distribution, coordination between authorities and operators, and clear criteria for prioritising projects. In practice, renewable projects, storage assets, interconnections and electrified industrial infrastructure depend on a chain of decisions in which every delay can affect the cost of capital and the execution schedule.
The Council also introduces a new category of priority projects dedicated to the security and resilience of existing electricity infrastructure. This would make it possible to finance critical components needed for emergency repairs of electricity interconnectors. The issue is gaining relevance in a European context marked by risks of sabotage, physical or cyberattacks, and the need for grids capable of supporting a more electrified and decentralised energy system.
As energy shifts away from centralised generation towards portfolios combining renewables, storage, self-consumption and flexible demand, the grid becomes part of the economics of every project. Installed capacity, land, technology or the commercial contract are no longer enough on their own; what matters is the credibility of the whole route to market: connection, evacuation, congestion risk, imbalance costs and the ability to monetise flexibility.
The same logic extends to consumption. The electrification of industrial processes, onsite generation, behind-the-meter storage, charging of electric fleets, heat pumps and PPA contracts all depend on grid availability and quality. In such a system, the question is no longer only how much electricity costs, but whether the infrastructure allows consumption to become more flexible, more predictable and better aligned with price signals.
The next step is negotiation with the European Parliament on the final form of the legislation. The Council states that negotiations will begin after Parliament adopts its position, with the aim of reaching an agreement as quickly as possible in 2026.