Net zero roadmap for accelerating Europe energy transition

Written by: Dr Farooq Sher, Department of Engineering, School of Science and Technology, Nottingham Trent University.

Summary

Europe’s energy transition is now in a phase where the speed of delivery and system integration are more important than headline ambitions. Renewables already provide nearly half of the EU’s electricity, but they still account for only a quarter of total final energy consumption. This is the electrification task that still needs to be accomplished in buildings, transport, and certain sectors of industry. Electrification is wonderful for decarbonization, but it also increases peak demand, the rate of connection requests, and the need for a power system that must remain reliable and increasingly weather-dependent. The problem is no longer “can we build wind and solar?” but “can we connect them quickly, manage them intelligently, and balance them cheaply?” The age of the distribution network, the time it takes to deliver reinforcements, and the speed of connection are all causing queues and curtailment risks. Simultaneously, a high-renewables system faces multi-year variability in wind, solar, hydro inflows, and temperature-driven demand. If Europe is planning for “typical years,” it may be facing higher costs and difficulties in difficult years. This article argues for a joined-up net-zero roadmap built around a single delivery chain: clean power expansion, grid digitalisation, and storage/flexibility. Clean power is the supply engine. Digitalisation is the capacity unlocker that makes networks observable, forecastable, and controllable, allowing more hosting capacity and faster connections while physical upgrades catch up. Storage and flexible demand act as shock absorbers, stabilising the system and prices when variable supply swings or networks are constrained. The roadmap is Europe-wide, with a Central and Eastern Europe lens used only to explain why uneven infrastructure readiness and investment conditions can spill into Europe-wide price volatility and slower electrification. The core message is simple: net zero succeeds when the integration layer is treated as the critical path.

1. Why Europe needs a net zero delivery roadmap now

The research trajectory in the energy transition in Europe has proceeded in a definite “past → present → future” fashion. In the past, the key research and policy question was whether renewables could become sufficiently cheap and scalable to compete with fossil fuel-based power. That era is past. Today, the key research question is power system performance: how to operate a big, electrified economy on intermittent renewables without converting variability into volatility. The current data explains why the research agenda has changed. In 2024, renewables accounted for 47.5% of gross electricity consumption in the EU, up 2.1 percentage points from 2023 [1]. However, renewables accounted for only 25.2% of gross final energy consumption in the EU in 2024 [2]. The difference is the electrification challenge. This means that the power system must expand to decarbonise heat, transport, and industrial sectors, while also becoming more complex as new loads and resources increasingly connect at the distribution level.

It is for this reason that the “integration layer” is now the most prominent in both research and delivery. According to the EU’s grid action factsheet, “40% of distribution grids are over 40 years old, there was a 19% increase in distribution-level connection requests in 2021, and the investment needs of the electricity grid over the coming decade are approximately €584 billion [3].” These figures are important because they highlight the constraints that are binding: the age of the networks, the pressure on connections, and the extent of the capital programme. At the same time, research has become more critical and more realistic. Europe-scale modelling is now checking net-zero designs against a large number of past weather years to prevent the misleading comfort of “representative year” assumptions [4]. Storage research is now more likely to assess system value under varying constraints and time scales rather than treating storage as a single product [5]. Digitalisation research has shifted from “smart grid vision” to barrier analysis, interoperability, and governance, reflecting that scaling digital solutions has proved as much a regulatory and organisational challenge as a technical one [6].

Recent literature indicates that Europe-scale net-zero infrastructure is vulnerable to multi-year weather patterns, that storage value is a function of duration and system context, and that digitalisation (digital twins) can enhance observability and decision-making [4]. Nevertheless, Europe today lacks harmonised, comparable publicly available data on distribution hosting capacity and connection queues by country, as well as a common flexibility scoreboard covering storage and demand response flexibility [3]. This research breaks new ground by providing a sequenced, system-centric roadmap that links clean power expansion to digitalisation and flexibility as part of a single delivery chain and connects these to measurable delivery outcomes. The purpose and scope are to deliver a Europe-wide roadmap to accelerate net-zero delivery through clean power, digitalisation, and storage/flexibility, and to apply a CEE perspective to explain why a lack of balanced infrastructure readiness and cross-border integration matters to the entire system. The innovation is in the sequencing: focusing on digitalisation and flexibility as capacity enablers in the near term, rather than add-ons down the line, and basing the roadmap on open-access high-impact research and authoritative European and global institutions [7]. Figure 1 illustrates two points: first, renewables are already a leading source of electricity in Europe; and second, country-specific data suggest that grid constraints will differ across Europe; hence, a Europe-wide roadmap is still required to account for these differences in delivery.

Figure 1. Renewables share of EU electricity by country.

Source: Eurostat (bar chart in the 2024 renewables electricity release) [1].

2. Europe’s current starting point

The baseline consists of two levels: the progress made in the electricity system and the remaining gap in the overall energy system. Eurostat states that in 2024, renewables accounted for 47.5% of gross electricity consumption in the EU [1]. This indicates that the transition in the power sector is highly progressed. However, Eurostat also states that in 2024, renewables accounted for 25.2% of gross final energy consumption in the EU [2]. This is the “electrification gap.” It indicates that Europe needs to move more sectors onto the electricity grid and ensure that electricity is clean, reliable, and affordable at higher volumes and during larger peaks. The emissions trend is the climate context in which the importance of delivery speed is situated. The EEA states that net EU greenhouse gas emissions decreased by 36% between 1990 and 2023, and that a preliminary estimate indicates a 2.5% decrease between 2023 and 2024 [8]. These reductions are significant, but they also indicate that further acceleration is needed to go from “steady progress” to “net-zero delivery,” particularly as the remaining emissions become harder to reduce and more infrastructure-dependent.

Now, place the delivery bottleneck on the table. According to the EU grid action factsheet, “40% of the distribution grids are over 40 years old, and the number of distribution connection requests increased by 19% in 2021” [3]. These two figures account for why connection queues and “grid-first” constraints are now a reality: the need to connect has outpaced the traditional cycle of reinforcement. The same factsheet states that the “electricity grid investment requirement is approximately €584 billion in this decade” [3]. This is important because it means that delivery is no longer “projects,” it is a program.

The global context is important because Europe is developing in a crowded market. According to IRENA, “2024 sees record additions to the global renewable fleet, and the total global renewable stock is growing rapidly” [9]. Figure 2: The electricity roadmap and emissions outcomes. The key message from Figure 2 is that the path of emissions depends on infrastructure delivery, and slow grids and slow flexibility mean slow electrification and decarbonization.

Figure 2. EU net greenhouse gas emissions pathway (1990–2050).

Source: EEA chart “Total net GHG emissions in the EU” [10].

3. Clean power scaling that delivers under real variability

The expansion of clean energy in Europe is still necessary, but the success criterion has shifted. What is important is the availability of clean electricity, not just the capacity expansion. One of the major issues with the transition scenario is the overdependence on the “representative year.” This is remedied by studies that optimise a sector-coupled European net-zero energy system over 62 years of historical weather data (1960–2021) and explore the implications of variability [4]. The overriding policy implication is simple: a system optimised for the mean can be caught off guard by challenging but plausible years, which will raise costs and difficulties when the system is put to the test.

The second important aspect is that Europe’s geographical diversity is a strength, but only if it is leveraged. A study by Elsevier Energy on wind-solar complementarity in Europe finds that optimal coordination of wind and solar resources across countries can enhance use and mitigate variability, leading to increased capacity factors and reduced hourly variability in coordinated portfolios [11]. This again argues for a Europe-wide approach, where coordination and interconnection are not “add-ons” but a means to reduce system cost and increase reliability. Policy coherence is the enabling layer. In a study on “Advanced Approaches Towards Net Zero Policymaking,” the author argues that achieving net zero requires coherent policymaking that integrates technology strategies with regulatory, financial, and implementation capabilities [12]. One implication is that clean energy contracting must be synchronised with readiness for grid connection and flexibility services. Otherwise, the system will be prone to over-investing in assets that cannot deliver full value quickly.

Industrial feasibility is another limiting factor that requires more attention in the European discourse. The IEA points out that grids are poised to become the transition bottleneck in the global clean energy transition and that investment requirements must increase significantly to keep up [7]. On the other hand, studies on manufacturing and supply chains show that the feasibility of transition is not solely dependent on technology costs but also on industrial capacity and logistics. [13] The significance is that if Europe fails to secure transformers, cables, and storage components, the transition timeline will become hypothetical. Figure 3 explains why flexibility and resilience are first-order constraints in the roadmap for a high-renewables Europe.

Figure 3. A robust Europe net-zero system across many weather years.

Source: Nature Communications (Gøtske et al., 2024) [4].

As Figure 4 illustrates, wind and solar do not behave the same way across Europe. Some countries have a higher average level of generation (capacity factor), while others have more “up-and-down” generation (variability). When you treat groups of countries and technologies as a single portfolio rather than planning each country separately, you can reduce variability and increase the average usable generation. This is the key point: cooperation across borders can help Europe get more reliable, clean power from the same kinds of resources [11].

Figure 4. Benefits of coordinated wind–solar portfolios across Europe.

Source: Elsevier Energy (Prol et al., 2024) [11].

4. Digitalisation as the accelerator of Europe’s energy transition

Digitalisation is the quickest lever to unlock integration capacity, with physical upgrades slowly catching up. It enhances observability, forecasting, automation, and coordination, enabling greater hosting capacity and faster connections without sacrificing security. One of the most important operational facts is that a large part of the transition’s complexity is now in the distribution networks. This is where EV charging, heat pumps, rooftop PV, and behind-the-meter batteries are connected. When visibility is limited, operators are naturally cautious. This caution becomes a hidden cost: slower connections, more restrictive exports, and higher curtailment risk. Research on digital twins can be applied in this context because it reflects digitalisation as an end-to-end capability rather than a tool. An Elsevier publication discussing the “electric digital twin grid” literature explains how real-time information and modelling can enable monitoring, forecasting, and decision-making [14]. This is policy-relevant because it connects digitalisation to hosting capacity, faster operational response, and more efficient use of infrastructure.

However, digitalisation is not hindered solely by hardware. An Energy Policy barrier analysis on the digitalisation of the distribution grid identifies and prioritises barriers, with policy recommendations [6]. The key is governance: if incentives are paid only for physical capex and do not reward DSOs for reducing connection times or realising hosting capacity through smart operations and digitalisation, digitalisation will remain piecemeal. This is precisely why “digitalisation” must be considered a fundamental infrastructure programme; not optional IT. Forecasting is a second digital enabler with a specific focus on Europe. An open-access Earth System Science Data publication offers and assesses forecasts of electricity demand and wind and solar power production for 28 European countries over 5-day to 1-month horizons, explicitly integrating energy operations with meteorological services [15]. This is directly pertinent to Europe, as improved forecasting can reduce operational surprises and lower balancing requirements, particularly as variable renewables increase.

Figure 5 illustrates the “digital twin” cycle for a power grid: it takes real-time data from sensors and systems, uses it to model the grid, predicts what will happen next, and then uses that prediction to inform decisions about congestion management, fault repair, or expansion planning. The key benefit is speed and accuracy, and the ability to “try before you buy” with decisions on the virtual twin before making them on the real system, which is helpful in a world where grids are under stress from the rapid growth of renewables and electrified demand. But the model also suggests the difficult bit: a digital twin is only as good as the data it’s based on. If the distribution networks have poor sensors, poor data standards, and poor interoperability between systems, the “digital twin” can provide confident-sounding answers that aren’t right. So, it’s very useful, but it’s not magic; without strong data governance, cybersecurity, and validation, a digital twin can become a rich man’s toy rather than a useful tool [14].

Figure 5. An electric digital twin grid framework.

Source: Elsevier (Sifat et al., 2023) [14].

Figure 6, in essence, shows that the digitalisation of the distribution grid is not hindered by a single problem, such as “we need better software.” Rather, it is a series of problems that mutually support each other: regulation and incentives (what the DSOs are allowed and rewarded to do), data and interoperability (systems that do not speak to each other), skills and organisational capacity, and initial cost and procurement complexity. The important thing to note is that even if the technology is ready, the DSOs will not quickly scale it if the regulation rewards only traditional capex (new cables and transformers) and does not reward outcomes such as shorter connection times, increased hosting capacity, or proven use of flexibility. A second problem the figure suggests is fragmentation: if every country (or even every DSO) does digitalisation in its own way, you are left with “islands” of smart grid capabilities that are difficult to connect, which, in turn, would make Europe-wide flexibility markets and TSO-DSO coordination less effective. Thus, the figure is essentially a warning that digitalisation is as much a governance and incentives challenge as a technology challenge [6].

Figure 6. Barriers to distribution-grid digitalisation.

Source: Energy Policy (Monaco et al., 2024) [6].

5. Storage and flexibility at scale as shock absorber of high renewables

Storage and flexibility can mitigate variability becoming volatility. They can stabilise supply variations, enable frequency and adequacy, minimise curtailment, and mitigate congestion if applied correctly. The key is to apply the principle that flexibility is infrastructure, not niche markets. The Commission states that 4.9 GW (12.1 GWh) of utility-scale storage was installed in Europe in 2024, bringing the estimated cumulative total to over 13 GW [16]. This is good, but the system requirements must keep pace with the growth of renewables. ENTSO-E system planning identifies large, cost-effective storage power requirements by 2030 as part of the European least-cost trajectory [17]. The value of storage depends heavily on the system, particularly for long-duration storage. Open-access research in Nature Communications examines the value of long-duration energy storage across various grid conditions and explains how duration, cost, and system requirements affect the optimal flexibility mix [5]. This is important because policy can inadvertently favour short-duration storage over multi-day resilience.

Modelling for Europe has modelled the economic efficiency argument for storage. An RSC Energy & Environmental Science paper models storage in a renewable European economy and demonstrates how storage can reduce the pressure to overbuild capacity, with variations across countries [18]. This finding is important because it changes the focus of storage from a reliability solution to a cost-cutting solution. In terms of technology, ACS Chemical Reviews offers thorough reviews of rechargeable batteries for grid-scale storage and flow batteries, explaining why certain chemistries are suited to specific services and time scales [19]. The policy lesson is straightforward: markets should buy services (frequency response, ramping, congestion relief, energy shifting), and the technology mix will follow.

Flexibility can also be provided by demand. A Renewable and Sustainable Energy Reviews review of industrial demand response discusses challenges and the need for market integration and digitalisation to tap into industrial flexibility [20]. An Energy Reports paper on data centres as flexibility resources argues the same case: controllable loads can help the system if measured, and market rules permit [21]. The Renewable Energy Technologies offer a structured system framing for this section, with one offering a technology perspective and the other a systems and implementation perspective on net zero [22], [23]. This underpins the roadmap’s key message: flexibility needs to be built in from the outset. Figure 7 essentially illustrates a very simple yet important concept: without sufficient storage, you wind up overbuilding wind and solar just to meet the hours of the day when output is low. Storage allows you to “bank” excess electricity during hours of high output and use it later, so the system can meet reliability targets without as much additional generation capacity sitting idle most of the time. This is why the figure depicts storage as a system-efficiency resource rather than a backup resource [18].

Figure 7. Storage reduces the need for renewable overcapacity in Europe.

Source: RSC Energy & Environmental Science (Santecchia et al., 2023) [18].

The value of long-duration storage (LDES) is also made clear in Figure 8: it is not “always valuable” either. It is system-dependent: the number of wind/solar resources, the strength of the grid, the amount of existing short-duration storage, the flexibility of demand, and the frequency of multi-day shortages. In regions with frequent periods of “low renewables” lasting several days, LDES can avoid expensive backup sources or overbuilding, thereby increasing its value. In regions with mostly hourly variability and robust grids, the additional value of very long duration may be lower [5].

Figure 8. Value of long-duration storage under different system conditions.

Source: Nature Communications (Staadecker et al., 2024) [5].

6. Cross-border coordination and the Central and Eastern Europe lens

The optimal path for Europe is not exclusively national, as the electricity sector is increasingly interlinked. Coordination across borders helps share variability, improve adequacy, and lower the overall system’s cost. This is where the CEE perspective becomes systemically relevant: imbalances in delivery in any area can have a spillover effect on Europe-wide price volatility and the pace of electrification. The TYNDP 2024 plan of ENTSO-E outlines more cross-border capacity and storage power as cost-effective by 2030 [17]. The most important point is that interconnection and flexibility are not niceties to be added but are part of the efficiency architecture of a Europe dominated by renewables.

CEE is important because distribution preparedness and investment terms can vary from one area to another. If some areas have slower cycles of network reinforcement or higher financing costs, delays in connection may persist, affecting prices. These, in turn, lower political will for electrification and the efficiency of the internal market. Equity and cohesion are also important considerations. Another research on regional disparities in the low-carbon transition found that imbalances in vulnerability and benefits can persist unless they are addressed [5]. This underlines the importance of the roadmap’s focus on Europe-wide delivery, with the transition having to be rapid across all regions, not just the easiest ones.

This is essentially what ENTSO-E is saying: “If Europe wants the cheapest reliable power system, we need more cross-border links and more storage.” The map (Figure 9) indicates where additional interconnection capacity is required and where storage will play a significant role, helping verify that variability is more easily managed when countries can share electricity and flexibility rather than each country developing everything on its own [24].

Figure 9. Europe-wide system needs for interconnection and storage.

Source: ENTSO-E TYNDP 2024 public webinar slide “2030 System Needs” [24].

7. A phased action roadmap for Europe’s net zero transition

A helpful roadmap is sequenced: unlocking the next bottleneck through early actions. First, remove connection friction. The grid action factsheet emphasises increasing connection pressure and ageing distribution infrastructure [3]. The key policy action is to prioritise connection lead time and hosting capacity as core performance metrics, not as secondary information that emerges only late in the process. Second, digitalise early as infrastructure. Digitalisation is an immediate capacity enabler, but the literature on barrier analysis demonstrates that governance and incentives can hinder it [6]. To speed up implementation, regulators should focus on rewarding outcome-based performance, such as reduced connection time and proven flexibility in procurement, in addition to capex spending.

Third, develop flexibility in tandem with renewables. The Commission’s storage baseline indicates progress, but system planning suggests greater demand and a more varied resource mix [16]. The key objective is to ensure that storage and demand response resources can operate effectively in balancing, congestion, and adequacy markets. Fourth, enhance Europe-wide integration. Cross-border coordination and interconnection are efficiency instruments in a high-renewables system [17]. This is where the CEE lens is important: Europe-wide resilience depends on the strength of the system across all regions.

Policy work is the governance backbone of this roadmap: net zero requires policy alignment across technologies, regulation, finance, and implementation approaches [12], [23]. Further, a structured context for technology and innovation choices related to system-level delivery is required [22]. Figure 10 marks the policy “roadmap” milestone in the net-zero EU roadmap. It shows the binding direction of travel to achieve climate neutrality by 2050, with the crucial milestone of reducing net greenhouse gas emissions by at least 55% by 2030 compared to 1990 levels (also known as “Fit for 55”). It is useful in the final roadmap section because it converts all the technical policies (clean energy deployment, grids, digitalisation, and storage) into one headline policy outcome that policymakers care about: the 2030 milestone and the 2050 goal.

Figure 10. EU 2030 climate target milestone on the path to climate neutrality.

Source: European Commission – “2030 climate targets [26].

8. Risks and safeguards that keep net zero affordable and reliable

The biggest political risk is affordability. If renewables expand more quickly than integration capacity, consumers will pay for curtailment, congestion, and emergency balancing. The safeguard is to treat the grid and operational capacity as the critical path and to accelerate the delivery of both physical infrastructure and digital capacity unlocking [3]. Reliability risk increases as the system becomes more weather dependent. Strong European modelling across many past years demonstrates the dangers of average-year planning in a high-renewables system [4]. The safeguard is resilience planning and a flexible portfolio that spans short- and long-term time scales. Cybersecurity risk increases with digitalisation. The safeguard is a security-by-design architecture, segmentation, monitoring, and resilience testing. The key point is that slowing down digitalisation is not a safeguard; digitalisation is also what enables safe operation and optimal use of flexibility. Supply chain risk increases as global deployment expands. IRENA’s record growth is a signal of sustained competition for equipment and materials [9]. The safeguard is a joint industrial strategy, skills, and procurement planning.

Social acceptance risk can slow both renewable energy and grid infrastructure projects. The safeguard is open planning, community engagement, and sharing, plus designs that minimise unnecessary infrastructure by better utilising existing infrastructure through digitalisation and flexibility. Figure 11 illustrates the long-run trend in EU average household electricity prices, distinguishing between the energy/supply/network price component and taxes/fees. It illustrates how price levels and tax components evolved during the energy crisis, forming a strong argument that price volatility and affordability are significant transition risks. It underpins the safeguard argument that grid investments, flexibility, and storage lower the risk of high prices due to congestion and balancing.

Figure 11. Development of EU household electricity prices and taxes, 2008–2025.

Source: Eurostat [27].

9. Conclusion

The European transition is no longer about technology. It is a delivery issue. The pace of change will be best achieved when the development of clean energy is balanced with modernised grids, deep digitalisation to quickly unlock capacity, and storage and flexibility that maintain reliability and keep prices stable. If Europe pursues each of these as separate projects, it will risk the failure mode of the next decade: big pipes on paper, slow links in reality, rising curtailment pressures, and political blowback when citizens feel the sting of volatility rather than the promise of progress. The biggest shift in thinking is to recognise that the integration layer is the headliner. Digitalisation is not a nice-to-have; it is the unlocker of capacity that makes distributed electrification feasible. It enhances visibility and forecasting, enables faster operations near the edge of the system, and converts distributed flexibility into system-wide services. Storage and flexible demand, in turn, are the shock absorbers that protect the system from variability becoming volatility. Without the shock absorber layer, a low-carbon system will be brittle in tough weather years and costly in peak and congestion events. The second mindset shift is to think Europe-wide. A more integrated system reduces overall costs by sharing variability, but it also means that a weak link is contagious. This is why delivery in Central and Eastern Europe is not a secondary storyline. If some areas are less advanced in grid modernisation or flexibility deployment, Europe will face a lifetime of price volatility and an uneven transition experience, just the kind of environment that hinders electrification and undermines social support. If Europe can structure the transition around integration bottlenecks, modernising and digitalising grids first, developing flexibility in parallel with renewables, and improving coordination across borders, then net zero becomes not just a goal, but a deliverable program that stands up to real-world weather, real-world supply chains, and real-world politics.

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