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Tracking Demand Response 2020

More efforts needed
Hector Martinez Ruupyvdsnek Unsplash

About this report

2019 was a mixed year for demand-response technology. Deployment increased across the United States and Australia, as well as in some European markets. However, regulatory uncertainty in key European jurisdictions, and strategic shifts on the part of important market participants increasingly trying to consolidate their energy service and product offerings, have dampened the DR outlook. Global capacity of all forms of demand-side flexibility expanded 5% year-on-year in 2019, which is ten times lower than the level required in the SDS.

Demand response potential in the Sustainable Development Scenario, 2018-2040

Tracking progress

Global demand response deployment slowed in 2019 as regulatory uncertainty loomed over key markets and a number of important market participants reduced their investment activity. Installed capacity increased in the United States, Australia and selected European markets.

Unfortunately, the demand response base is small relative to the magnitude of effort needed in the SDS: by 2050, the global inventory of flexible assets in the residential, commercial and industrial sectors needs to be ten times higher than it is today. Less than 2% of the global potential for demand-side flexibility is currently being utilised.

Selected demand-side flexibility initiatives, 2020

Demand Response Map
Selected demand-side flexibility initiatives, 2020
Demand Response Map

In Europe, a strong growth market in earlier years, as well as auctions and other deployment mechanisms, obtained mixed results in 2019. In Italy, a total 280 MW of capacity were commissioned by the system operator across the country, while in Ireland 415 MW of demand response capacity was awarded in a T-4 (four-year-ahead) auction.

Capacity market payments in the United Kingdom were suspended as the European Commission continues to review whether the country’s capacity auctions violate EU state aid rules. Despite this regulatory uncertainty, the annual T-1 (year-ahead) auction was carried out, but the capacity awarded was less than half that of the 2018 auction. However, the carryover of projects from earlier years resulted in an overall increase in capacity in the United Kingdom.

Similar regulatory concerns curbed expansion in other European markets. In Poland, Tempus Energy followed its successful challenge of UK capacity market rules with a new filing over similar discriminatory concerns – namely, that longer-duration contracts are awarded to generators rather than to demand response providers. The more mature markets such as Ireland – where generators are awarded ten-year contracts as opposed to the one-year guarantees given to demand response providers – may also face similar challenges in the near future.

Australia remained a global leader in virtual power plant (VPP) development as new offerings emerged, but the value of these business models has yet to be proven. Currently only one VPP (of only 1 MW, managed by AGL) is registered to provide flexibility services in the highly valuable frequency control and ancillary services markets, which in Australia carry the bulk of flexibility provision.

VPPs will continue to spread as solar-plus-storage offerings are now routine in new construction, and developers continue to partner with utilities and third parties to reduce their own grid investment costs and reduce energy bills for prospective buyers.

In the United States, the combined wholesale demand response capacity of all regional system operators grew to 27 GW (around 6% of peak demand), with an additional 5 GW offered through retail programmes. Progress was particularly strong in California, where capacity under auction doubled to 373 MW. Load control, interruptibility services and reserves markets also expanded elsewhere in the country.

In Asia, China made some progress in accommodating new distributed energy business models, which could pave the way to greater demand-side flexibility. Despite some resistance from the two national grid companies, which are wary of potential grid fee reductions, China launched a broad programme of 26 pilot projects to trial consumer-level energy trading and balancing. In Japan, new offerings included a VPP from Eneres (owned by telecommunications company KDDI), scheduled to be launched in 2021 with 10 000 enrolled customers. 

In a trend carried over from 2018, utilities are following their strong activity of previous years by reducing their acquisitions, partnerships and in-house product and service offerings. As business models consolidate, utilities are increasingly trying to establish proofs of concept and predictable growth.

Conversely, oil companies are more actively investing in technologies directly related to demand-side flexibility.

Having acquired the European battery manufacturer Saft in 2018, Total invested in Go Electric, a microgrid developer. Spanish oil giant Repsol bought Ampere, a residential storage developer that also provides flexibility services by managing their batteries through a VPP, while Shell acquired Limejump, a UK aggregator and VPP provider.

The boundaries between VPPs, demand response providers and prosumers became further blurred in 2019. The current market for VPPs alone is estimated at 20 GW, with one-third of capacity focused exclusively on demand response.

Major utility companies further diversified their offerings into VPPs that include demand response packaged with other forms of demand-side flexibility and generation.

In Europe, EDF acquired Energy2market, a German VPP company with over 4 GW of capacity, including behind-the-meter batteries and demand-side assets. Engie acquired Tiko, a Swiss residential VPP, following its acquisition in 2018 of the UK DR operator Kiwi Power. In the United Kingdom, Kaluza, a subsidiary of OVO energy, was launched in 2019, offering a range of demand-side flexibility services including: residential battery load management in partnership with Sonnen; residential heat storage in a joint initiative with appliance manufacturer Glen Dimplex; and a field trial of smart EV-charging in London.

In a key development, distribution network operators are more frequently sourcing flexibility locally. As the presence of distributed generation, EVs and other electrified loads in distribution grids increases, distribution network owners and operators will try to defer or avoid grid upgrades and reinforcement by using less traditional “non-wire” alternatives such as local demand-side flexibility. These alternatives have already made inroads in the United Kingdom, the Netherlands, Germany and Norway either through third-party platforms or direct procurement by distribution system operators.

Although demand response has the potential to provide a diverse range of flexibility services, in most jurisdictions around the world demand-side flexibility still exists only as an interruptibility service when a large industrial company provides load reduction services for reserves or other short-term markets.

Expanding the reach of demand response will require that markets and regulatory environments allow it to compete equally with other forms of flexibility (including unbundled electricity service markets and regulated utility models). Platforms and participants to deliver demand response in these different environments will also be necessary.

The success of more sophisticated forms of flexibility, including VPPs, demand response aggregation and locally provided flexibility, also depends on the evolution of rules and regulations. Recognition of the importance of aggregation is still lagging: some countries, such as Austria and the Netherlands, are deploying demand response mechanisms but do not yet formally recognise the role of aggregators.

Because applications and end uses are so varied, policies must also be sufficiently diverse to ensure that market designs are adequate, and markets must be granular enough that the capacity of demand response to meet certain system needs is obvious – particularly local forms of flexibility that can be exploited by distribution system owners and operators. 

New business models such as aggregation, VPPs 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 more advanced forms of system services.

Through trials or other direct-observation methodologies that reflect local regulations and electricity sector structures, governments and regulators should study the feasibility of using ICT platforms and smart contracts to help consumers respond to price signals or signals from system operators, and they should also expand flexibility offerings.

Furthermore, they should consider implementing time-based rate programmes as well as regulatory structures that monetise flexibility at the point of use.

Finally, governments should facilitate consumer and third-party (including aggregator) access to smart-metering data and dynamic pricing and other signals.

While the majority of demand-side flexibility will continue to provide basic services such as load reduction until 2030, applying demand response to new services could provide new revenue streams and decrease transaction costs, allowing distributed energy resources to participate in a wider range of markets.

Big data analytics, monitoring and control will increasingly allow VPPs to adjust consumption and production patterns and tap into new flexibility at smaller scales. Beyond wholesale markets, local flexibility particularly should be increasingly encouraged – including careful consideration of the interaction between distribution system operators and transmission system operators and between local and wholesale capacity or balancing markets.

The vast majority of demand-side response potential lies in large industrial thermal loads and processes, thermal comfort in buildings (i.e. heating and cooling), EV charging and behind-the-meter storage and generation.

The instantaneous load from EVs especially can be an order of magnitude higher than the average household load. Managing EVs in particular could therefore both help integrate higher shares of EVs and enhance overall system flexibility, which could in turn enable greater renewable electricity generation. Smart charging strategies that shift the time of day that EVs draw electricity from the grid can unlock some of this flexibility.

There are currently few smart charging schemes (the leading pilots are in the Netherlands, Germany and California, and there is a new pilot project in London), even though untapped flexibility potential is already significant.

If demand response from EVs were enabled for the full EV fleet today, 2 GW of flexibility would be immediately available to the system – similar to the total amount of non-pumped hydro storage capacity.


Francisco Laverón (Iberdrola), Alex Lajoie (Nice Grid)