Globally, investors and developers are finding their clean energy project pipelines at risk due to a lag in transmission infrastructure. The projected electricity demand growth is boosted not only by the strong global macroeconomic recovery but also by new and emerging segments of electric vehicles, heating, and data centres. The upcoming renewable energy-led generation projects can meet the incremental demand without much reliance on conventional resources. But that is feasible only if the transmission linkages are assured.

A sharply changing energy mix has left the power transmission segment appearing as a bottleneck. Most transmission utilities are already grappling with crunched capacity, as evident occasionally in the grid curtailment measures or a pause in taking grid new connection requests. To be sure, they are responding to the emerging problem through network development plans and rate requests. The need may be for much more. At the same time, the incentive structure is in focus because the regulated return on equity must adjust to attract the capital needed for anticipated grid spend.

Policy goals are not the only determinants of demand. The mainstream adoption of applications based on Artificial Intelligence and Big Data technologies is generating an unprecedented demand for the electricity business through Data Centres. Globally, they share about 1-2% of the total power consumption, which is poised to reach 3-4% by the end of the decade (Goldman Sachs, 2024). Strikingly, the US and European Data Centre markets’ growth has altered the power demand and planning outlook for the utilities and regulatory authorities alike to the extent that some of the authorities placed restrictions on permits (e.g. Amsterdam municipality in the Netherlands). Many other markets are similarly anticipating a demand spike as developers seek new locations to set up the Data Centre capacities.

The global electricity demand outlook is largely a culmination of the growth factors at play in major economies/markets. In this regard, it should be noted that local factors influence a significant part of the countries’ electricity demand picture. In the US, for instance, the estimated 3% growth in 2024 reflects a sharp spike over the country’s previous few years’ power demand trajectory. At the same time, China’s 6.5% estimated growth in 2024 is the result of the country’s moderated growth phase, involving a mix of high-growth and lagging sectors. The regional focus in this report will be largely on the Americas and European regions and will include references to others based on context.

The sharp rise in global electricity demand is likely to be met with a record rise in clean energy-based power supply, especially from solar PV. Globally, by 2025, solar power is expected to cover more than half of the electricity demand growth. Furthermore, solar and wind together could make up over three-quarters of the demand rise during the same forecasted period (IEA, 2024). By then, renewables are likely to outpace coal- based power generation. Such projections just reinforce the energy mix shift underway across countries at varying speeds. The changing emissions profile of the power supply segment is almost a given worldwide.

Power sector emissions may plateau progressively through 2025 as renewable energy penetration displaces coal- and gas-based power capacities. There is at least a consensus about retiring the unabated coal (i.e. without carbon capture and storage technology) usage in the power sector. As of April 2024, the G7 countries agreed, in a joint communique, to shut down the unabated coal-based power plants by 2035 (Guardian, 2024). The phase-out of coal, as a baseload option, involves issues that must be managed through alternate solutions, such as hydroelectricity, gas, and nuclear power, for network stability and reliability.

Utilities and power generation companies are using gas-based power as a bridging option in this transitory phase – switching/replacing coal units and/or balancing the intermittency of clean energy resources in the power mix. While gas as a fossil energy source too must be phased out, it has a role in bridging the ongoing energy transition route. Between 2017 and 2023, the share of gas in the total global electricity supply has been range-bound at 23%-24% (Energy Institute, 2024). The fuel pricing dynamics meanwhile influence the switching from coal to gas where feasible. The wholesale power market design in countries has a major contribution to these decisions (IEA, 2023). Competing fuel options such as nuclear power are also in consideration.

Nuclear power is an alternate bridging energy resource for many countries. It is also on the rise, as evident in the progress of nuclear fleets across the major economies, including France (renovation works), Japan (decided to restart reactors), and China, India, Korea, and Europe, among those setting up new capacities. While globally, its contribution is unlikely to assume any significance, it will be an instrument for some of the economies to achieve ambitious decarbonisation goals.

The market design has a vital role in ensuring the alignment of supply with demand. With wholesale power market transactions, utilities and network operators tie up the necessary capacities through contracts with generators for baseload, peak or contingency requirements. Reliance on certain fuel types is typically reflected in the power market prices. In 2023, for instance, the wholesale electricity prices declined in many countries, as compared to the high levels of 2022. Such a decline took place in parallel to the general fall in energy commodity prices, notably coal and gas.

The role of renewable energy sources is seen at a much more granular or localised level. In 2023, for instance, the SPP power market region of the US registered the lowest wholesale electricity prices in locations where wind power generation was disproportionately higher than others (Berkeley Lab, 2024). A similar view was shared by the Australian regulator about the wholesale electricity prices in Southern Australia in 2023 – rapid growth in renewables slashed the prices and reduced dependence on coal- based generation units (ABC News, 2024). In such a scheme of things, the market design or structure is vital.

In May 2024, the European Council signed off on updated rules for wholesale power market reforms in the European Union (European Council, 2024). This is a culmination of the reform proposals taken up in the aftermath of the energy price volatility in 2022 (arising from a natural gas blockage amidst the Ukraine-Russia armed conflict). EU’s market structure so far, with its marginal cost-based pricing (European Commission, 2024) made the gas-fired stations setting the market-clearing price. With limited clean energy capacities, prices spiked in 2022 due to a shortage of natural gas.

In 2023, Europe got relief from the declining natural gas prices and has, since then, reduced its reliance on natural gas. However, several countries in the region continue to rely on gas in their respective energy baskets. Furthermore, the interconnected nature of the European energy markets revealed several notable points during 2023. For instance, in France there was a shift in position from being a net importer to a net exporter as nuclear and hydroelectric output grew rapidly. Germany, however, became a net importer due to the phaseout of nuclear (ACER, 2024). Integrated energy markets enabled by cross-border interconnections have an important role in the region’s energy prices.

Berkeley Lab’s recent study of the US market illustrates the value of transmission linkages. In 2023, despite the fall in average wholesale electricity prices in the US, the market value of added transmission interconnection/links (equivalent to savings as compared to new local generation capacity) was higher than before. This means that, for given conditions of demand and supply in US electricity in 2023, expanded transmission would have provided the most value even when the wholesale prices had declined (Berkeley Lab, 2024).

Grid companies’ profits are determined by the regulated returns on investments. Since such entities are natural monopolies in the business, the regulators set the maximum returns on equity. However, there is a trade-off in such a regulated incentive-setting mechanism. While consumer interests are important, the returns must attract capital for the enhanced investment requirements. Higher returns on equity correspond to higher grid charges. The spike in energy costs in 2022 made it difficult for many regulatory authorities to allow upward revision in tariffs. All the same, rate hikes are being implemented to reflect the rise in capital and operational costs of managing the grid. This marks a departure from the near-stagnant rates over the last 5-10 years, especially in the US and European grids. The process of recovering the higher costs varies. In Europe and the US, the grid charges percolate down to the end consumers connected to the grid. There are other approaches being considered. The US utility American Electric Power proposed a new approach to the regulators, involving levying higher charges for the large new demand (thereby avoiding higher rates for residential consumers) to fund the cost of grid buildout. The UK regulations allow factoring in both capex and opex by adding both (called Totex) in the regulatory asset base for calculating returns. To be sure, capex still skews the overall calculations, but progressively, there is recognition accorded to the network modernisation initiatives such as renovation and digitalisation in the cost recovery.

Over the years, in most countries, deregulation of the traditional vertical integrated undertakings ensured that power transmission is undertaken as a separate business entity (EPRG Cambridge, 2024). The restructuring process also led to the bifurcation of system/network operations and transmission asset operations for objectives of efficiency and neutrality in the business.

While the general direction of progress has been towards deregulation and restructuring, different countries have chosen the paths best suited for local needs. This means implementing variants of the deregulated structure for the country’s power transmission business. For instance, in Spain and France, the state has full or partial ownership of the grids, even as the business is run by private entities. Ownership and operation, too, are unified into the same enterprise in some countries, notable examples being Spain’s Red Eléctrica de España, Italy’s Terna and the UK’s National Grid. All of them own the grid assets besides carrying the grid operator’s mandate. In September 2024, the UK government announced the acquisition of the grid operator to make it a publicly owned entity (Guardian, 2024) marking a shift against the privatisation done in 1990.

The business restructuring in power transmission over time also contributed to the rising role of the private sector. Most grid companies are either fully private-owned or not under direct government control, at least for the European and US grid entities. Presently, grid investments are predominantly driven by the private sector, which is better placed to tap into the capital markets than, say, municipal- owned entities (e.g. the French distribution system operators), which rely on bank-led financing. Even in countries with state-owned unbundled transmission utilities (e.g. India), there are competitively bid transmission projects to further the network expansion plans. Other countries, such as Brazil, follow the private concessionaire model for the transmission network – CTEEP is the private concessionaire responsible for about 30% of Brazil’s total grid- connected power supply.

It is noteworthy that the markets with robust competitive wholesale power market structures generally coincide with an independent transmission system operator business. Yet, countries such as Australia, Brazil, Canada, and the US still manage to combine vertically integrated power entities with competitive wholesale power. Regulatory frameworks play a vital part in the entire chain, ensuring not only the rules of the power market but also the returns in the business.

Grid companies’ profits are determined by the regulated returns on investments. Since such entities are natural monopolies in the business, the regulators set the maximum returns on equity. However, there is a trade-off in such a regulated incentive-setting mechanism. While consumer interests are important, the returns must attract capital for the enhanced investment requirements. Higher returns on equity correspond to higher grid charges. The spike in energy costs in 2022 made it difficult for many regulatory authorities to allow upward revision in tariffs.

All the same, rate hikes are being implemented to reflect the rise in capital and operational costs of managing the grid. This marks a departure from the near-stagnant rates over the last 5-10 years, especially in the US and European grids. The process of recovering the higher costs varies. In Europe and the US, the grid charges percolate down to the end consumers connected to the grid. There are other approaches being considered. The US utility American Electric Power proposed a new approach to the regulators, involving levying higher charges for the large new demand (thereby avoiding higher rates for residential consumers) to fund the cost of grid buildout. The UK regulations allow factoring in both capex and opex by adding both (called Totex) in the regulatory asset base for calculating returns. To be sure, capex still skews the overall calculations, but progressively, there is recognition accorded to the network modernisation initiatives such as renovation and digitalisation in the cost recovery.