T he installed transmission infrastructure is due for renewal at a scale unprecedented by historical standards. While all TSOs are steadily augmenting their respective networks, the urgency of the energy transition makes it an unusual phase for all. The economically advanced economies are in focus due to their rising renewable energy penetration, an ageing transmission asset base, and drastically changing electricity demand profile. Emerging market economies, while largely relevant in the discussion, differ in terms of their energy growth trajectory and their position in the energy transition. Yet, with time the trends are converging between advanced and mature markets.

This chapter briefly reviews the major pointers that shape the narrative around transmission network expansion, grid projects like interregional interconnectors, the technology profile shaped by Direct Current-based transmission systems, and the role of modernisation in the investment plans drawn for long-term network development.

The electricity grid has expanded by approximately 1 million kilometres per year in the past decade. Most of this growth has occurred in the power distribution segment responsible for last-mile connectivity. Globally, the bulk power transmission network makes up only about 7% of the total grid line length, totalling 5.3 million kilometres.

The growth of this network varies significantly between developed and emerging market economies, with countries like China, India, and Brazil leading the way in the latter category. Advanced economies have seen a 9% increase in their transmission line length, with notable growth in the European Union (12%) and the US (3%). While line length is a useful measure of network size and growth, it’s important to note that some utilities upgrade transmission lines to reinforce or improve existing lines without laying new ones. This can decrease total line length as multiple lower voltage lines are replaced with single or fewer lines of higher capacity. Such anomalies in growth trends are more likely in the ageing transmission networks of mature economies.

It is largely predictable that the power transmission networks of emerging market economies will grow faster than those of the developed markets of the US and Europe. At a granular level, the global growth trajectory in transmission has a few noticeable patterns across the regions and markets. For instance, the investment objectives vary across the regions. In emerging economies, the grid must expand to accommodate the spiralling demand growth from a historically low base. For perspective, the per capita power consumption in developing economies is at about 2,500kWh compared to over 10,000kWh in the developed ones (S&P Global, 2024). Excluding China, the developing economies spent about $70 billion on grids during 2020-2022. In the same period, the developed economies had committed about $170 billion, predominantly for network strengthening and reliability.

The urgency of grid reliability or reinforcement investments is driven not only by the age of assets but the changing risk profile. Climate change and the resulting extreme weather events present a major risk to grid network assets. In the US, for instance, between 2012 and 2023, one in three of the power outages were due to extreme weather (Swiss Re, 2024). There is similar evidence in Europe, where utilities managed blackouts arising from weather events. The region’s integrated network may have aggravated the impact. In June 2024, the grid blackouts of Albania, Bosnia and Herzegovina, Croatia and Montenegro were caused by 400kV lines tripping, which were in turn triggered by abnormally high temperatures. Around the same period, grid malfunctions and outages were reported in Italy and Spain due to the unprecedented spike in load of high temperatures (Montel, 2024).

A delayed or prolonged network expansion process is progressively becoming untenable. Equipment shortages are not the only issue. The lead time involved in getting the transmission grid assets online, whether new or refurbished, needs a relook for possible compression. For instance, permitting and approvals, which constitute a critical intermediate (and regulatory) stage of the capacity addition process, are also the major contributors to delays and cost overruns. In an acknowledgement of this issue, the US Department of Energy, in April 2024, notified revised rules of issuing permitting decisions on new transmission lines within two years of applications, replacing the average four years earlier (Utility Dive, 2024). There are similar considerations in the EU region, where permits can take 4-10 years for grid reinforcements and 8-10 years in case of new high-voltage lines (EC, 2023).

Progressively, timeliness is a vital attribute in TSOs’ network expansion frameworks. It was always a given that the transmission network capacity would expand by some magnitude to meet the foreseen demand and load. The energy transition investments, however, impose an urgency. To sum up, as above, some of the notable factors to track in the ongoing capacity addition phase include the measures towards building grid resiliency against extreme weather risk, reinforcement activities for service reliability, managing the flux in the material supply chain, and compressing the traditionally long lead time in project development.

Over the years, an important development in power transmission networks has been the rise of interconnector lines – typical high-voltage transmission lines that connect one region/ province or a power market with another to offer mutual benefits such as effective prices, generation utilisation and grid stability. Their role is vital in a world of rising renewable energy penetration and the challenge of integrating them with minimum volatility.

The EU signifies the same with several cross- border transmission interconnectors operational in grid stabilisation and demand management. By 2025, EU’s grid operators are expected to make at least 70% of their transmission available for cross-border trading. While challenging, the potential benefits can vastly outweigh the costs. It can, for instance, help minimise the grid congestion cost – about €4 billion was spent in managing EU grid congestion as of 2023 (ACER, 2024).

The European experience is also informative for the role of transmission interconnectors in avoiding grid blackouts. In 2022, the downtime in the French nuclear power plant fleet was significantly offset by the interconnections with its neighbouring power markets. There are other examples, such as that of Luxembourg, where imports through the interconnections with France and Germany help meet over 80% of the total power consumption (Rabobank, 2023). The NordLink (Norway-Germany) and North Sea Link (Norway-UK) have played a major role in stabilising the grid through Norway’s surplus hydropower and the North Sea’s excess wind energy. Relatively smaller countries such as Denmark have used the transmission interconnectors strategically in energy planning and avoided building redundant power generation capacities.

Tapping into the promise of interregional transmission involves working around multiple challenges. At a fundamental level, these links are generally facilitated by inter-government agreements. The political buy-in is crucial before the technical and institutional factors (such as formulating uniform grid codes, a regional grid operator, etc.) are brought into the picture (IEA, 2023). This brings forth a multitude of coordination challenges, which can delay or even jeopardise them. Geopolitical factors, too, enter the fray. The EuroAsia interconnector project is one example of such a project being impacted by geopolitics (the Middle East conflict, in this case).

The challenges and delays in project development ultimately boil down to the bankability of projects. With high upfront costs and long gestation periods, timely financial closures are vital for developers. Multilateral investments, as has been seen in EIB funding, often help as bridging resources. However, the successful deployment of the interregional transmission projects would require much more than the potential benefits.

Long-distance power transmission, as is typical in renewable energy-based projects, involves higher voltage ratings for technical efficiency. Even in grid reinforcement and strengthening projects, TSOs uprate the existing lines to enable higher efficiency. Within the high voltage transmission segment, the High Voltage Direct Current (HVDC) technology has gained significant currency in recent years. Its rising deployments have had a favourable view amongst operators and developers. Practically, all the interregional transmission interconnector lines are based on HVDC systems.

HVDC has been found significantly beneficial in long-distance connectivity due to its lower technical losses and competitive costs as compared to the traditional Alternating Current-based transmission systems. Also, with progress in deep-sea cables technologies, submarine HVDC projects present a much more competitive option than before. The development of such systems might be crucial to tap into the emerging offshore wind power segment in many countries. Offshore wind power projects are, in fact, a major demand driver for the HVDC systems. The German Federal Network Agency’s long-term electricity development plan includes building 35 HVDC lines to connect 70GW worth of offshore wind energy by 2045 (Enerdata, 2024). Offshore wind is similarly an important resource in the UK (50GW by 2030s), for HVDC systems are being engaged – the Eastern Green Link is one of the largest HVDC projects planned in the UK and will be developed as a cross-border link between Northern Scotland and the UK (Eastern Greenlink, 2024).

Among other prominent technologies in recent years is the Dynamic Line Ratings (DLR) system, which is used for grid reliability and integrating renewables by adapting line capacity to real- time conditions. Due to their potential benefits, DLRs have lately joined the category of ‘grid- enhancing technologies’, with the federal regulatory authority endorsing its merits.

Beyond the grid-enhancing technologies, the TSOs’ focus is also shifting increasingly towards digitalisation measures for potential efficiency gains. The share of digital technologies in total spending has risen from 12% in 2016 to about 20% in 2022. The increasing share of distributed generation-based renewable energy sources has made it difficult to track and predict the direction of energy flows within the grid, which is why digital technologies are assuming a vital role. Artificial Intelligence (AI) based systems are the latest innovations in this regard. Notable recent applications include AI-based demand forecasting to improve the accuracy of short-term energy predictions and address fluctuations caused by weather and other factors.

In summary, the technology profile of the TSOs broadly shows steady signs of shift in terms of the adoption of higher voltage ratings, HVDC-based deployments, grid-enhancing technologies such as DLRs and the greater involvement of digitalisation in operations. To be sure, all such measures are rooted in the local requirements and the corresponding cost-benefit analysis. Most of the emerging new technology measures are likely to be mplemented in a staggered manner involving pilots and proof-of-concepts.

The introduction of advanced technology systems and innovations in power transmission tends to be oddly placed against an ageing asset base. While software-based innovations can get around the old assets, the hardware part needs replacement. While most of the countries have a predominant share of 10+ years in the transmission asset age, the acute challenge is in the advanced economies where a major part of the asset base is aged over 20 years. The US Department of Energy’s estimates suggest that 70% of the US transmission lines are over 25 years old and are approaching the end of their 50-80 years lifecycle (DoE, 2023). The European grid infrastructure is similarly grappling with an outdated structure, with average age of high-voltage transmission lines at 30 years (ERT, 2024).

The backdrop of capacity addition is as much about grid modernisation as it is about expanding its access. Retrofitting with higher efficiency conductors, for instance, could help in minimising the network losses by 10% – 20%. Similarly, replacing outdated transformer units with improved models could rationalise energy consumption by up to 12% (Deloitte, 2024). The reinforcement measures also include boosting the physical infrastructure to make it withstand extreme weather possibilities. The key objective is to ensure that the transmission grid stays available all the time.

Utility-scale renewable energy projects would connect to the transmission system, hence the focus on grid preparedness. There are instances that highlight grid unavailability impacting generation projects. In 2023, the Polish grid did not have the capacity to accommodate renewable power several times over the year (ECFR, 2023). Modernisation and refurbishment can be regarded as important growth drivers of the spending and outlay devoted to the network development plans. In October 2023, the US Department of Energy announced $3.5 billion in funding across 58 grid reinforcement and strengthening projects. Utilities are chipping in with the rest. Modernisation is at the centre of the UK TSO’s planned £58 billion investment by 2035 towards meeting decarbonisation goals (Current, 2024). EU’s annual €23 billion spend on the grid network (including both transmission and distribution) is primarily led by refurbishment needs. The European Commission estimates point to an investment requirement of almost €600 billion for the transmission and distribution networks by 2030. Most of it goes to upgrades and modernisation.

The scope of grid refurbishment is almost equivalent to establishing a new super grid over the existing one. The lumpy nature of such investments means that even with the best efforts, progress will involve a protracted path. It may also mean that the industry may have to put up with bottlenecks in the short-term at current rates of growth in renewable energy projects.