For transmission system operators, the long- term network development scenarios are subject to rising uncertainty. Policy objectives in decarbonisation and net zero must be taken into account. At the same time, the ground reality of grid preparedness may force TSOs to take a different direction. Gas-based power, for example, is replacing coal-based power in some markets due to a lack of reliable grid balancing options. The legacy grid management practices are also facing obsolescence with the rise in renewable energy penetration, most strikingly in the European region, where instances of negative grid prices have been frequent. As a result, flexible generation and energy storage are gradually becoming integral to the utility power mix.

This section reviews some of the key factors influencing transmission utilities’ growth plans. It discusses renewable energy penetration and recent developments that indicate its implications, the role that conventional energy resources are playing in utilities’ plans, and the emergence of grid-scale energy storage. The concluding part describes some of the major demand segments that have lately influenced the investment outlook.

The role of renewable energy is projected to rise in importance through 2025 and 2026. With coal in retreat, renewables could overtake coal in the global grid-connected power supply by 2025 (IEA, 2024). In the advanced economies of the US and Europe, most of the incremental electricity demand could also be met through renewables. Over two-fifths of the renewable energy capacities in the next decade will be through wind and solar energy. Such an emerging energy mix entails a different way to plan transmission network development.

The countries experiencing high renewable energy penetration in their grids illustrate the dynamics well. Broadly, the task of integrating large-scale wind and solar deployment in the bulk power system comprises working on three areas. These include building/maintaining the response systems for short-term variability, putting in place sufficient generation to cover demand for all time blocks and ensuring frequency stability in the events of grid disturbance (NREL, 2024). With fewer balancing assets, as in thermal power generation, integrating renewable energy resources is much more challenging and complex than before.

Renewable energy integration challenges extend beyond the technical requirements of stability and reliability. Power market transactions are sensitive to grid constraints. The European region displays some of these issues. For the first eight months of 2024, the European region had negative grid prices for 7,841 hours. In some cases, prices reached—€20 per MWh or even lower during the same period (WEF, 2024). This was the result of a surge in renewable power, especially solar, which the grid could not absorb during the time blocks. The frequency of such events is likely to rise as more renewable capacities connect to the grid and may be detrimental to renewable project pipeline and prospective investment if left unchecked. The solutions to mitigate such integration challenges include a combination of measures, such as energy storage, flexible generation options, and advanced grid management technologies, among others. Many of these steps are already under implementation worldwide.

Market mechanisms are part of the measures that help bring flexibility. Market-led flexibility might be urgent for countries characterised by high renewable energy penetration. One example is the Netherlands, where the transmission system operator awarded ‘capacity limitation contracts’ to a solar PV plant in November 2023. Such a contract is a form of congestion management wherein the solar PV plant is entitled to a pre-defined compensation instead of a possible backing down when needed for grid network stability (PV Magazine, 2023). While this signifies the short-term grid constraints, it also underscores the role of market design in aligning capacity.

Progressively, the transition of the existing centralised grid structure to a decentralised one is central to the future flexibility in power systems. Such a structure entails a fundamental shift, wherein generation units are dispersed and close to consumption. In such a scheme, transmission network assets address the significant systemic imbalances instead of being limited to power dispatch.

Over time, energy transition has progressed on multiple fronts of the power mix. For instance, the phase-out of coal-based power generation is mainly in parallel with the exponential rise in the share of clean energy sources in grid- connected power. Other power resources, such as natural gas, hydropower, and nuclear power, are amid similar changes in contribution to the grid supply. It gives rise to a complex framework of inputs for the grid operators who must plan and secure regulatory approvals for the grid network assets well in advance. In particular, the grid operators’ mandates on network reliability, stability and growth often face trade-offs against decarbonisation and net zero policy objectives.

The global push towards retiring unabated coal- fired power generation has notable pointers about the challenges. In May 2024, the G7 countries’ commitment to a complete exit from coal by 2035 (Guardian, 2024) is encouraging but also ambitious. The UK closed its last coal-fired power plant on September 30, 2024 (Guardian, 2024). By the end of 2023, about 21GW worth of coal-based power generation capacity had been retired. (GEM, 2024). However, the momentum slowed down in the US and the European regions due to their respective operators’ concerns about grid preparedness once the coal-based power is switched off.

In the US, the utility subsidiaries of CenterPoint Energy Inc., Alliant Energy Corp., and WEC Energy Group Inc. (all operating in the Midwest region) were among those entities that delayed coal retirements in 2023 to address short-term reliability concerns (S&P Global, 2023). The US Federal Electricity Regulatory Commission (FERC), in its testimony before a Senate hearing in May 2023, held that there is a potential crisis in some of the US power market regions, such as PJM, where capacity retirements could be faster than replacements. FERC’s submission at that time pointed to the 40GW of retirements expected in PJM by 2030, against only 15GW- 30GW of new units by then (Utility Dive, 2023). A select group of countries recently pushed back their coal retirement targets in Europe. These include France, Italy, Hungary, North Macedonia and Romania (BFF, 2024). It should also be noted that the 2022 European energy crisis (involving a natural gas crunch) prompted many in the region to revive old coal-based power plants.

The energy transition impact extends beyond coal. Natural gas has emerged as a vital resource for balancing grid requirements in peaking, short-term support, and the like. For many utilities, gas-based generation units are vital for grid-level contingencies. This is at least one primary explanation for the rise in coal-to-gas switching among European utilities. Favourable gas prices since 2022 have enabled such a transition. Notable countries in this regard include Germany, Poland and the Netherlands, where coal and gas capacity is available (Reuters, 2024). In February 2024, the German government announced plans to hold auctions for new gas-based power plants, which would be converted to hydrogen-based plants by the mid-2030s. The planned gas-based plants in Germany will support the transitory phase of shifting to near-zero emissions in power supply by 2035 (Clean Energy Wire, 2024).

The intersection of grid reliability requirements and a cleaner energy mix drive a revival of nuclear power capacity. Its lower emission profile combined with baseload capabilities helps provide it an edge over conventional energy resources. At the COP28 Climate Change Conference of December 2023, over 20 countries signed a joint declaration to triple nuclear power capacity by 2050. As a result, the nuclear power project pipeline is sharply rising globally. Between 2024 and 2026, capacity worth 29GW could be commissioned globally, led primarily by emerging market economies (IEA, 2024). In advanced economies, the capacity pipeline faces development and financing delays. All the same, nuclear power generation is forecasted to register an annual average of 3% growth through 2026. The projected growth nets out the impact of ongoing phase-outs or retirements worldwide.

In summary, the energy transition towards cleaner energy resources impacts grid stability and reliability. The legacy dependence on conventional options in coal and gas-fuelled capacities must be replaced with equivalent capabilities. Presently, the grids are not fully prepared. This is why coal retirements slowed down, while gas-based power appears to be the best feasible interim option to balance intermittent wind and solar energy. Meanwhile, nuclear power is poised for a comeback as policymakers and utilities pull out all stops for an emission-free grid profile.

The globally concerted push towards energy transition is the primary driver in accelerating the storage capacity deployment. Grid-scale energy storage attracts the maximum interest as it contributes critically to the clean energy investment space. An estimated $37 billion of clean energy investment in 2023 was towards batteries (IEA, 2023). Trend-wise, it was three times the quantum in 2021.

Utility-scale batteries are applied across a spectrum of grid management roles. This impacts the business prospects for the standalone battery developers, for whom the battery revenue stack signals the commercial viability and project returns. Notably, the energy storage applications are contingent on the wholesale power market regulations in the respective countries. The relative attractiveness of the markets is thus determined by the extent to which regulations enable storage-based power transactions.

Frequency regulation, for instance, is one of the leading areas of battery storage application, even as its relative share has declined over the years. Conversely, a few other applications, such as arbitrage, gained share sharply in the last five years, as battery units proved instrumental in capturing price advantages of peak and off-peak grid power transactions. Also noteworthy is the rise in the deployment of batteries specifically for the excess renewable energy generation injected into the grid. Its relative share has more than quadrupled in the US market.

Lately, investors are relooking at another important, though lagging, sub-segment of energy storage – pumped hydropower. It is the most widely used grid-scale energy storage technology globally. However, its growth plateaued due to the legacy challenges associated with gestation period, development barriers, uncertain costs, environmental and location constraints. Yet, the trend (IRENA, 2023) indicates a pick-up in capacity since 2021. This is because of pumped hydropower’s capabilities as a mature long-duration energy storage resource – an increasingly sought-after and scarce option for grid operators worldwide. One example of the rising interest is the UK’s £1.5 billion Coir Glas Pumped Hydropower Storage project, marked as the country’s first such project in the last 40 years.

Unlike buildings, the district heating segment continues to be relatively nascent in deploying electrification processes. Its decarbonisation has been largely untapped so far, with fossil fuels contributing over 90% of the total heat supply. Many entities are thus exploring a mix of options to meet the requirements, including low-emission electricity and other energy resources such as secondary heat (waste heat recovery), distributed energy systems, etc. Grid connection will be an integral part of the infrastructural support such systems will need in the coming years. The demand from this segment could be substantial once the systems are commercialised for implementation at scale.

Electrification, however, is one of many demand drivers for grid connectivity. The rise in cloud computing and the mainstream rollout of Artificial Intelligence-based applications have spiked the demand for Data Centres. These are energy-intensive facilities, made more so with complex, high-processing technologies and robust telecom coverage. Data centres accounted for about 1-1.3% of global electricity use, which is expected to rise with the increasing demand for digital services (IEA, 2023). Around 40% of a data centre’s energy consumption powers its cooling and ventilation systems. Leading tech companies like Facebook, Google, and Microsoft are setting benchmarks by committing to power their data centres with 100% renewable energy. These companies also invest in Power Purchase Agreements to finance renewable energy projects, thus reducing their carbon footprints and operational costs (IEEFA, 2020).

For utilities in some of the leading data centre markets, i.e. in the US and Europe, the spike in demand from data centres has been unexpected and, in some cases, led to short-term challenges in accommodating grid connection requests. The US market is a notable case of illustration. The Data Centre segment appears to have shifted the country’s power demand outlook, contrasting the near- zero level of demand growth over the previous decade. The implications, though short-term, are severe. Goldman Sachs’ estimates point to $50 billion worth of utilities’ investments required in the US to support the Data Centre demand. Furthermore, the incremental Data Centre demand could drive about 3.3bcm worth of new natural gas demand in the US by 2030. The European context is not much different, as the region hosts around 15% of such global facilities. Countries like the Netherlands have had to pause grid connection requests to manage grid stability and avoid unmanageable grid congestion (Goldman Sachs, 2024).

To conclude, some of the significant demand segments for power networks lie in sectors such as electric vehicles, heating of built-up spaces, and Data Centres. The quantum and pace of each vary widely. Transport electrification is the fastest among sectors in terms of the demand growth outlook, for which both transmission and distribution networks must be prepared. The demand in the building segment is relatively flat, but a strong push towards electrification arises from power-to-heat technology systems like heat pumps. Lastly, the Data Centre segment is set to account for an unforeseen rise in power demand in the US and Europe. These demand segments are likely to influence the grid network development plans globally.