IEA (2020), Smart Grids, IEA, Paris https://www.iea.org/reports/smart-grids
In this report
Investment in electricity grids declined for the third consecutive year in 2019, falling 7% from the 2018 level to just under USD 275 billion. In contrast, investment in the full suite of digital technologies, including advanced metering infrastructure, utility automation and electric vehicle charging infrastructure, made up more than 15% of total grid spending.
The United States overtook China in 2019 to lead grid investment for the first time in ten years. Following the continuous upward trend begun a decade ago, US investment increased 12%. Higher activity was required to upgrade aging infrastructure, digitalise and electrify sectors such as transport and heat, and secure the grid against natural disasters and cyberattacks.
Regulators throughout the US continued to evaluate transitioning to performance-based regulation, which rewards utilities based on the services they provide rather than the volume of infrastructure they develop. Common in other jurisdictions including Europe and some Asian markets, performance-based regulation could encourage smarter grid solutions and “non-wire” alternatives to traditional grid investment.
China’s downward investment trend accelerated in 2019, dropping 11% mainly as a result of regulatory changes and reduced grid tariffs. Grid reform to encourage private investment in distribution networks continues, albeit at a slow pace. Reforms began in 2015 and 400 pilot projects were initially approved, but only 100 are currently in development.
In Europe, investments remained stable at nearly USD 50 billion, with rising expenditures allocated to upgrading and refurbishing the existing grid as variable renewables and electrification become more important.
The European Union continued to make good progress towards grid decentralisation. The Clean Energy Package envisages creation of a new organisation of European DSOs, mirroring the role ENTSO-E has in transmission grids. It also calls for greater market equality for demand-response technology and defines new opportunities for energy storage, preventing the double taxation of storage assets for both charged and discharged energy. Projects in Germany and France are actively evaluating the how storage can be an asset for electricity grids.
In India, despite a strong effort to strengthen inter- and intrastate transmission capacity in the last years five years, the pace of buildout slowed (-20%) in 2019.
Smart grid investments remain focused on hardware, from digital substations to smart metering and other power engineering equipment. While reporting on software expenditures is not yet commonplace, utilities around the world have indicated they are increasingly adopting sophisticated software tools. Utilities and grid companies in Europe (Iberdrola, Enel, Rte and e.On) and in the United States (Exelon, Duke and Edison International) reported record spending on software.
Although substation automation has been a trend in recent years, in 2019 utilities expanded the use of software platforms to monitor and control them, notably through digital twins.
National Grid partnered with Utilitidata and Sense to create a “digital twin” of the grid, mapping power flow, voltage and infrastructure from the substation to the home. American Electric Power also announced the digital twinning of their transmission infrastructure, developed in collaboration with Siemens. Elsewhere, PA, with San Diego Gas & Electric Company, developed a world-first system using AI to prevent power outages by predicting asset failures weeks in advance.
Enel offers a prime example of how digitalisation can increase operational efficiency and improve quality of service for a grid owner or operator. In just ten years, Enel reduced the System Average Interruption Duration Index (SAIDI, an indicator of grid quality) by 65%, and it is currently spending nearly one-third of its investment budget on digital technology.
Quantifying benefits remains difficult, however. Many regulatory regimes reward cost savings, whereas smartening the grid often produces other qualitative or softer benefits (e.g. enabling other technology or business models; reducing emissions; creating jobs) that cannot be easily rate-based.
While some utilities have begun reporting direct financial savings, improvements in traditional reliability metrics such as SAIDI and SAIFI remain the mainstays to evaluate costs and benefits of smartening the grid.
At the transmission level, new high-voltage technologies permit greater network interconnections as well as the connection of remote energy resources. Digital smart-control technologies such as dynamic line rating allow transmission networks to operate at higher capacities, closer to their physical limits. They can also improve management of interconnections among regions and countries.
The rate of investment increase for interconnecting transmission systems slowed significantly in 2019, despite a few key announcements, including a new link between Denmark and the United Kingdom and continued activity in China (a 1 100-km-long Shanbei-Wuhan link with 8 GW of capacity). An executive order in the United States banning foreign-supplied transmission grid devices that could threaten national security clouds the outlook.
In Europe, while the future arrangement of the internal electricity market remains uncertain following Brexit, the share of electricity transmission Projects of Common Interest (PCIs) that were either on schedule or ahead of schedule increased for the second year in a row.
Experience from 2019 shows that new technology alternatives can avoid or defer investment in traditional transmission and other network infrastructure. The benefits demand response and storage technologies can offer to networks remain contentious. Regulations will need to evolve to reflect their new roles, including the leveraging of flexibility from consumer aggregation and grid congestion.
Governments, regulators and utilities should facilitate the adoption and use of novel assets for distribution system operators, including technical options such as advanced voltage and reactive power controls, closed-loop operations and non-wire alternatives such as distributed static storage systems.
They should also explore advanced tools for cost-benefit analysis of investments in managing distributed energy resources. Focus should be placed on developing “future-proof” grid codes that exploit the full capabilities of smart inverters, active power control and other measures for managing distributed energy locally.
Within the set of tools valuable for operators, innovation should be accelerated to enable more granular-scale energy monitoring and management, including production and load forecasting.
Governments, regulators and utilities should also define the roles and operational boundaries of aggregators and virtual power plants.
Governments can collaborate with equipment manufacturers, network owners and operators, utilities and third parties to create “sandbox” environments in which new distributed energy business models can be operated in real-world conditions to identify the least-cost integration options to scale up operations.
Network stakeholders at all levels should develop joint platforms for technology appraisal and standard setting (for physical and digital assets), and for exploring potential grid governance conflicts at different levels, particularly in the link between distribution and national network owners.
Although market structures vary, it is necessary to revise roles and responsibilities at all levels of grid governance as data and physical systems become more granular and distributed, and as more participants become involved.
As new services and technology platforms develop, the need for devices to communicate and operate seamlessly across all levels of the grid increases. Central to smart grids is the capability for technologies to be deployed in one part of the energy system and interact with elements in different sectors and geographies, and to be used by various stakeholders all along the electricity value chain.
Lack of interoperability among the various elements (e.g. charging infrastructure, smart metering infrastructure, remote monitoring and control equipment) is often the main obstacle to scaling up and transferring solutions that have been proven in another network, city or system.
Technical roadmaps will be required that lay out the necessary evolution of standards and interoperability of both digital and traditional electricity infrastructure as the energy system continues to evolve.
Luciano Martini (RSE), Michael Huebner (AIT)