IEA (2021), Demand Response, IEA, Paris https://www.iea.org/reports/demand-response
About this report
Nevertheless, even faster progress is needed: 500 GW of demand response should be brought onto the market by 2030 to meet the pace of expansion required in the Net Zero Emissions by 2050 Scenario (NZE), a tenfold increase on deployment levels in 2020. In the NZE, the equivalent of 15% of average annual demand can be shifted to some extent by 2050 (shares are higher in many advanced economies with demand response markets in operation today). Demand response can be unlocked through actions taken in this decade to open markets to demand-side participation, encourage new business models and establish controllability standards for equipment and appliances.
There were many positive demand-response regulation and implementation developments in 2020 and 2021. Favourable policies in several countries, such as Australia, Belgium and the United States, addressed some of the barriers to widespread demand-response deployment in power markets, while the number of capacity market auctions increased and prices broke records.
However, more ambitious policies and rapid implementation are needed for alignment with Net Zero Emissions by 2050 trajectories. By 2030, the global inventory of flexible assets in the residential, commercial and industry sectors must be 10 times higher than it is today, including the flexibility provided by the emergence of grid-connected electrolytic hydrogen production. At the same time, further investments in smart grids are also needed to support the uptake of demand side flexibility. For more information, please refer to the smart grids section.
The power system transformation that is taking place to support net zero trajectories is putting pressure on both supply and demand, creating the need for more flexibility, which can be increasingly obtained through demand-side resources, including demand response systems.
On the supply side, the share of renewables in total output in the Net Zero Emissions by 2050 Scenario expands from 29% in 2020 to over 60% in 2030, driving the need for additional system flexibility. At the same time, flexibility provided by thermal power plants is set to decrease in many markets, with decommissioning of conventional power plants already in progress in countries such as Germany, France, Chile and the United States.
Massive changes are also expected on the demand side. As electrification of all end uses grows rapidly in the Net Zero Emissions by 2050 Scenario, the share of electricity in final energy demand expands from 20% to 26% by 2030. Rapid electrification, especially of transport and heating, alters the shape of demand curves. Several jurisdictions, including Canada, the European Union, Japan and Singapore, recently announced strategies and targets for EVs and charging infrastructure. This could be an important demand-side flexibility resource if drivers are offered for attractive smart charging propositions, but it could also negatively affect the power system without adequate management. For example, private and uncoordinated charging might raise evening peak loads, resulting in network congestion and the need for further grid investments.
To maintain security, electricity system flexibility (defined as hour‐to‐hour ramping ability) more than doubles to 2030 in the Net Zero Emissions by 2050 Scenario. Battery storage and demand‐side response are poised to become major sources of flexibility in advanced economies as well as in emerging market and developing economies, together meeting almost a quarter of flexibility needs globally by 2030, on their way to providing around half of flexibility by 2050. The role of demand response grows most rapidly in advanced economies.
At all levels of the power system, digitalisation will be key to scale up demand-side flexibility and leverage small-scale flexibility resources, with more advanced real-time energy demand visualisation and analytics and smart controls being among the main technological enablers. However, growing dependence on ICT systems across the power network means that strategies are needed to mitigate the risks associated with failures of these communication channels, which should ensure supply security and power system resilience.
At the same time, digitally enabled power system transformation could stimulate the development of more innovative business models and new revenue streams.
Promising action has been taken worldwide to either promote the use of demand-side response to provide flexibility or improve existing programmes. For example:
- Australia approved a wholesale demand response mechanism, opening up the demand response market to consumers and aggregators as of October 2021. The focus is on large industrial and aggregated customers of a similarly large size, capable of curtailing demand.
- Belgium adopted a capacity remuneration mechanism that allows the participation of demand-side response operators and is aimed at ensuring security of supply, especially during the phaseout of nuclear capacity, expected by 2025. The first T-4 auction is planned for 2021.
- Singapore is reviewing existing demand response programmes and schemes, particularly to improve remuneration methodologies and penalty and compliance rules. The changes are to be implemented at the end of 2023.
- In the United States, system operators in the six capacity and ancillary services markets regulated by the Federal Energy Regulatory Commission were mandated to remove barriers to the participation of distributed energy resources of more than 100 kW, including demand response, renewables, EVs and energy efficiency, starting in August 2021.
Other countries are adopting important measures to increase demand response uptake:
- Chile launched a power system flexibility strategy focused on market design, regulatory frameworks and system operation.
- China is in the process of issuing regulations on operations and ancillary services to encourage the use of storage, user-adjustable loads, load aggregators, virtual power plants and other resources in power system ancillary services, currently under consultation.
- Colombia extended tax incentives to non-conventional sources of energy and energy efficiency projects, including smart metering and demand response.
However, the scale of change needed to meet Net Zero Emissions by 2050 climate objectives requires that actions be accelerated immediately and throughout the upcoming decade to translate into meaningful impacts.
Demand-side flexibility can be leveraged in diverse ways. The most common service offered globally is interruptibility, provided by large industrial companies, while in some regions flexibility is procured through wholesale and capacity markets. Alternately, demand response aggregators can provide frequency control ancillary services, as in Australia.
After an uneven 2019, the European market appears to be reverting to strong growth in 2020 and 2021. In 2021, the United Kingdom secured 239 MW of demand-side resource capacity in its T-1 (one-year-ahead) auction – a considerable increase from the 84 MW awarded in 2020 – owing to a record clearing price of GBP 45/kW/year. In turn, there was a slight decline in the T-4 (four-year-ahead) auction, to 1 GW from the 1.2 GW awarded in 2020. In Italy, the system operator awarded total capacity of 4.4 GW of virtually aggregated mixed units in 2021. Meanwhile, the French market for demand-side flexibility has grown by ~0.6 GW in 2021 (to 1.5 GW), thanks to a subsidy ceiling increase to EUR 60 000/MW/year – double the previous year’s level.
Tesla and Energy Locals are building the world’s largest virtual power plant with Government of South Australia support. Designed to test the technical capacity to provide services to energy markets, it has the potential to connect 50 000 solar and home battery systems.
While the United States remains the strongest market for demand-side flexibility because several states already have mature capacity markets, the Covid-19 pandemic presented an opportunity to re-evaluate ways to improve consumer participation. Building on existing manual demand response programmes, “bring your own thermostats” schemes, which are gaining popularity in the United States, offer consumers incentives to adjust their thermostats at peak times. For example, the Los Angeles project, which involved over 16 000 smart thermostats, aimed to deploy 25 MW of flexible power capacity by the end of the summer of 2021.
At the same time, rolling blackouts caused by wildfires in California in summer 2020 and extremely cold weather in Texas in winter 2021 prompted authorities to reassess the adequacy of current market designs and regulatory approaches, including for demand response to contribute to reliability and resilience of the power system in case of increasingly likely extreme weather events.
In Asia, China is implementing demand response programmes and market-based mechanisms with different configurations and participants, including virtual power plants, in several provinces. For example, Hubei signed demand response agreements for 1.8 GW and Zhejiang was expected to reach 4 GW of peak-shaving load in 2020. In Japan, 1.8 GW have been assigned for emergency peak reductions and 4 GW of demand response have been awarded in the capacity market, to deliver services in 2024. In addition, new offerings included a virtual power plant from Fujitsu, which will be using Autogrid’s platform and is targeting USD 34.7 million in sales, while Eneres (owned by telecommunications company KDDI) aims to enrol 10 000 residential customers by the end of 2021.
In the first part of 2020, the Covid-19 pandemic significantly reduced acquisitions and investment activity in demand-side flexibility businesses, but they returned to pre-pandemic levels in Q4 2020.1
Some utilities and energy providers strategically acquired, invested in or partnered with companies specialising in innovative solutions, including virtual power plants and smart charging for EVs. Engie increased its strategic stake in Connected Energy, a company that combines second-life EV batteries to create energy storage systems, while EDF acquired Pod Point, one of the largest EV charging providers in the United Kingdom, and Iberdrola invested in Wallbox, a smart charging system provider. Enel X expanded its geographic focus by entering the intelligent charging market in India through a 50-50 joint venture with Sterling and Wilson, a leading engineering company. Eaton partnered with Virta, a virtual power plant and EV charging equipment provider, entering grid balancing markets, and acquired Green Motion.
Oil companies are also strengthening their position in demand-side flexibility and EV charging markets. Shell acquired Next Kraftwerke, a German renewables trader and virtual power plant operator. It also invested in LO3 Energy, an accounting tool developer that supports innovative DER business models, and Net2Grid, an advanced residential energy monitoring company. The British multinational oil and gas company BP acquired Open Energi, a digital technology company that connects DERs with power markets. Eni has partnered with Kaluza to provide smart energy solutions for energy retail in France, and on the EV front, BP invested in Freewire Technologies while Shell acquired ubitricity.
Implementing the right policies, digital technologies and new business models will be essential to scale up demand-side flexibility and reap its benefits. Governments and regulators should adopt a systemic approach and involve a broad set of relevant stakeholders through consultations and participative processes.
To maximise their use in line with the Net Zero Emissions by 2050 Scenario, demand-side resources should be appropriately valued and allowed to compete fairly with supply-side sources of flexibility through mechanisms such as demand-side bidding in electricity markets and more granular frequency control ancillary services markets. Adequate incentives should also be in place for consumers to actively participate in the provision of flexibility through their supplier or third-party aggregators.
Demand-side flexibility should be included in power system planning and operations, and consideration should be given to its potential to optimise system investment, for example through non-wire alternatives such as the use of demand response to shift peak demand locally to defer or reduce investment in grid upgrades. When a scheme offers multiple advantages, for example avoiding network reinforcement and also limiting the need for generation, it is important that all benefits be recognised to strengthen the business case.
While regulatory frameworks should adequately encourage innovation, they should at the same time manage increasing system complexity and risk, thus reconciling conflicting interests. For instance, demand-response reliability should be ensured without hindering a fair participation of aggregators in the energy market. Procedures that were adequate for large power plants will have to be adjusted.
At the same time, cybersecurity, privacy and equity concerns should be addressed while maintaining data accessibility. How to shift from prescriptive regulation to more agile approaches is currently being discussed internationally through initiatives such as Agile Nations.
Meanwhile, standards and interoperability should be enforced at the national level and harmonisation pursued regionally and internationally. Ongoing work under the International Organization for Standardization, the International Electrotechnical Commission and the International Telecommunication Union can support these efforts. Open-source and software-driven approaches, such as LF Energy can also help advance this process.
With an increasing scale of local flexibility and wider participation of distributed resources to provide services to the system, including through virtual power plants and peer-to-peer trading, there is a greater need for data exchange and co‑ordination among stakeholders, mainly (but not exclusively) operators of transmission and distribution systems and aggregators, in countries where they operate.
Australia is developing and testing the concept of a distributed energy resource marketplace through the Energy Demand and Generation Exchange Project, which also includes a data exchange component. Meanwhile, India’s state of Uttar Pradesh has taken steps to promote the use of peer-to-peer trading, requesting the creation of secure and reliable transaction arrangements based on suitable accounting and billing systems.
Regulation is key to assign clear roles and responsibilities to enable the effective operation and use of distributed resources, as well as optimal power system investments. Several jurisdictions and international initiatives, such as ISGAN, are already pursuing enhanced co‑ordination between transmission and distribution systems. However, further guidance is needed to address conflicting interests and the sustainability of arrangements to avoid conflicts and direct competition for resources. For example, EU regulations set out principles for co‑ordination between Transmission System Operators and Distribution System Operators. Discussions on existing gaps and the need for a new network code are still ongoing.
To meet Net Zero Emissions by 2050 flexibility needs, specific sectoral provisions should be adopted as soon as possible to promote large-scale deployment of digital technologies and ensure that the demand side is ready to offer services to the power system. Attention should be paid to capitalising on multiple benefits through alignment with other sectors.
For instance, buildings are a potential source of flexibility. They should become more energy-efficient and be equipped with smart control and automation systems that can allow them to interact with the grid while effectively managing loads and distributed energy resources, including rooftop solar PV and battery storage. In the Net Zero Emissions by 2050 Scenario, mandatory zero‐carbon‐ready building energy codes that include requirements for demand flexibility and smart controls are introduced for all new buildings in all regions by 2030, and retrofits of existing buildings should happen at an average pace of 20 million dwellings per year to 2030. The European Union and the United States have already adopted roadmaps towards this goal.
At the equipment level in the Net Zero Scenario, countries implement minimum energy performance standards, complemented by requirements for smart controls. Priority should be given to higher-consuming devices and equipment, including air conditioners, water heaters and EV chargers. Some jurisdictions, such as South Australia, have already taken steps to accelerate the implementation of demand response requirements for certain appliances and equipment.
In rolling out EV policies and plans, smart charging systems and vehicle-to-grid schemes should be considered. The impacts of more EVs on the grid should also be taken into consideration before commissioning and deploying charging infrastructure. At the same time, charging vehicles when renewable energy production is high or peak demand is low should be incentivised, for example by prioritising charging at workplaces and public stations. Furthermore, smart and minimum functionality and device-level requirements could be mandated for private changing infrastructure, as is currently being discussed in the United Kingdom.
More incentives and funding should also be directed to R&D projects to enable innovative technologies to be brought to the market more rapidly. Initiatives such as Green Powered Future Mission can play an important role in accelerating this process by mobilising global action and investment.
New business models such as aggregation, virtual power plants and other distributed energy resource platforms offer great promise for enabling demand-side flexibility. However, most of the current offerings rely on traditional load reduction programmes, and not on automated and dynamic forms of system services.
The success of innovative business models relies on the adoption of enabling technologies such as smart meters and controls, and of supporting policy and regulatory frameworks. Governments should therefore facilitate consumer and third-party (including aggregator) access to smart-metering data.
Furthermore, they should simplify and encourage customer participation in various demand response schemes. This can be achieved through a broad set of measures. Price signals, such as time-based rate contracts and dynamic pricing schemes that reflect tension on the system in real time, give customers implicit incentives to shift their consumption when possible. Other contracts or regulatory structures explicitly monetise flexibility, for instance through annual payments for participating in demand-side response programmes or tenders for small-scale demand-side response. For example, in France almost 50% of the expected demand response volume for 2022 is reserved for sites of 1 MW or less.
Through trials or other direct-observation methodologies that reflect local regulations, electricity sector structures and user preferences, governments and regulators should study the feasibility of using ICT platforms, such as online marketplaces or apps, and smart contracts to help consumers respond to third party and system operator signals, thus expanding the range of flexibility offerings.
Besides technical and economic considerations, the scale-up of demand-side flexibility also depends on the attractiveness of the customer value proposition, balancing out cost savings with negligible impacts on comfort and lifestyle. It is therefore key for policymakers to focus on the central role of users and behavioural insights, especially when transitioning to more automated and complex forms of demand response. If not adequately managed, dynamic pricing can also dramatically increase consumer bills and discourage consumers from partaking in flexibility schemes.
Programmes such as the User-Centred Energy Systems Technology Collaboration Programme are working to address these issues.
Phil Lawton, Power Systems Engineer, Energy Systems Catapult
Rebecca Knights, Director, Energy Policy & Projects, Energy and Technical Regulation, Department for Energy and Mining, Australia.
Notes and references
Bloomberg New Energy Finance (2021), Q4 2020 Decentralised Energy Strategy Trends.
Bloomberg New Energy Finance (2021), Q4 2020 Decentralised Energy Strategy Trends.