As the penetration of renewable energy increases, the willingness of consumers to become active market players is expected to play an increasingly important role in balancing electricity demand with available supply. Consumers prepared to increase or reduce demand for a fee provide power systems with the flexibility needed to respond to variations in supply from wind and solar with no loss of supply security while at the same time decarbonising the grid
Managing power systems so that supply and demand are in balance has always been the overriding concern for power system operators. Imbalances compromise the reliability and the security of power systems and can cause power outages. In traditional power systems dominated by large, conventional generators, the burden of keeping the system in balance largely falls on the supply side, with power plants expected to ramp production up and down to meet changes in consumption. Demand is seen as being largely inelastic, or unresponsive to variations in price. Yet demand has already proven to be far more flexible than once thought. Demand response is defined by the Federal Energy Regulatory Commission (FERC) in the US as: “Changes in electric usage by demand-side resources from their normal consumption patterns in response to changes in the price of electricity over time, or to incentive payments designed to induce lower electricity use at times of high wholesale market prices or when system reliability is jeopardised.” It has been used in some countries for decades, often with time-of-use tariffs designed to encourage changes in demand patterns. But the growth of renewables is giving a new push to demand response efforts and sharpening the focus on demand response capacity that can be dispatched at the request of power grid operators. And alongside its traditional roles of levelling loads and shaving peak demand, demand response is increasingly being used to actively shift demand to times when green energy is being produced. In addition to “demand turn up”, another new development is the use of demand side management for short-term balancing needs that until recently were routinely provided by natural gas or coal-fired plants, says UK-based energy consultant David Milborrow.
Working together
“Demand response and decentralised renewables go hand and hand,” says Andrés Pinto-Bello, policy analyst with SmartEn, a Brussels-based association promoting digital and decentralised energy solutions. “With a higher penetration of variable resources, the system will need a technology that guarantees stability at times of peak generation” and can also help it remain reliable when production is low, he says. With the rise of both renewable and distributed generation, “electricity flows are changing a lot and we can see congestion developing in some areas”, says Eliano Russo, head of e-Industries at Enel X, which acts as an aggregator for about seven gigawatts (GW) of demand response capacity globally. “By activating demand response, you can remove some bottlenecks that otherwise would have been removed by investing in the grid.” In addition to avoided or deferred grid investments, demand response can also reduce the need for investments in peak generation. Henrik Madsen, professor at Denmark’s Technical University and head of the Centre for IT-Intelligent Energy Systems in Cities (CITIES), argues that demand response represents the most cost-effective way to integrate large amounts of wind and solar energy. “You can also build supergrids or invest a lot in batteries, but these are very expensive options. By enabling demand response and flexibility, I believe you can solve most of the problem at a very low cost.” Others stress that while demand is more elastic than once thought, it is not completely flexible either. “I think that there will be a natural level of saturation, limits to what consumers will be able to tolerate in reducing demand,” says Milborrow. With this in mind, some aggregators are already pairing demand response offerings with on-site storage, a trend that is expected to accelerate as the cost of batteries declines.
Danish demand response
In Denmark, the lack of energy-intensive industry means that demand response contracts with large industrial and commercial customers, typical of some other markets, are not a regular feature. Demand response here is mainly harnessed with the use of electric heat accumulators, huge water storage tanks with electric elements, which can be turned on when there looks to be a surplus of power and low electricity prices, and turned off when electricity is scant. While electric heat accumulators currently provide a relatively small portion of the ancillary services needed in Denmark’s balancing market, their importance and that of other demand response options is seen as increasing in the future. “We know that in the future, large power plants will have fewer operating hours and it will be more expensive for them to provide ancillary services, while there will be more renewables and power demand from electric vehicles,” explains Peter Markussen from the Danish electricity transmission system operator Energinet. “More flexibility will be needed.” Energinet can now count on about 800 megawatts of capacity in electric heat accumulators that can be used to provide demand response and ancillary services and that figure is expected to increase by up to 50% in the next few years. Energinet is also carrying out a number of pilot projects on demand response opportunities, including those that might be offered by electric vehicles and aggregating power demand from a group of buildings. “In most other European countries you have a focus on reducing demand when prices are high, but for us it is just as important to increase demand when there are high volumes of green energy and prices are low,” says Markussen. Electricity suppliers in Denmark are well aware of this need and have been focusing on incentives to encourage customers to buy power when the price is low and electricity is largely coming from wind energy.
UK, US and Ireland
A similar approach is also taking shape elsewhere. The UK’s National Grid in 2016 rolled out a “demand turn up” balancing service designed to encourage large energy users and generators to either increase demand, by shifting the time of use, or to reduce generation at times of high renewable output and low national demand. And in the US, the Arizona Public Service utility in 2018 launched a pilot project on “reverse demand response” to pay selected non-residential consumers to use more power when generators of electricity are having to pay the grid to take it off their wires when the supply of solar power is abundant. Irish transmission system operator Eirgrid says it has seen a significant increase in the number of demand-side service providers with the implementation of its DS3 systems services programme for the integration of renewables, which aims at allowing the grid to handle as much as 75% of non-synchronous renewable generation at one time by 2020, up from 65% now and a starting point of 50%. The programme is organised so demand response and all other service providers are paid more during high wind periods, when there is potentially more volatility, explains John Young, a senior engineer with Eirgrid’s innovation team. “We expect to have higher [renewables] targets after 2020 and so we will have to tap into even greater flexibility in the system,” Young says, a necessity that is expected to add up to the greater use of demand response. He believes one of the biggest challenges for system operators in incorporating a greater use of demand response may involve changing their way of thinking after decades dominated by conventional generation. Monitoring a system with aggregated demand may at least initially be a bit more difficult than one dominated by large, conventional generators, points out Young. As a result, system operators may also need time to move up the learning curve, gaining confidence in the capabilities of demand side products. Gauging the potential of demand response is not an easy task, and indications about current market capacity are seen as very rough estimates. In a 2017 report on digitalisation and energy, the International Energy Agency (IEA) forecasts that so-called smart demand-side responses in building, industry and transport could provide 185 GW of flexibility by 2040, avoiding $270 billion in new power infrastructure investments.
The IEA envisages almost one billion households and one billion connected appliances participating in demand response programmes by 2040
Guidelines and regulations
The latest figures from the European Commission, the EU executive body, indicate approximately 20 GW of demand response capacity has already been activated in Europe out of a current theoretical potential of 100 GW, which is projected at 160 GW in 2030. While the use of demand response is now uneven throughout Europe, Pinto-Bello says this should change with implementation of the EU’s recently adopted Clean Energy Package, along with network codes on electricity balancing guidelines from the European Network for Transmission System Operators. In fact, he says the impact of implementing balancing guidelines is already being seen. “Some countries that were quite closed until recently are starting to provide new services and pilot projects that are opening the balancing markets to independent market actors providing demand response.” Russo says regulations are one key factor in determining demand response potential. Regulations that provide clear indications about when customers may be called on to adjust demand and the forewarning they will be given are essential, as are rules allowing for the aggregation of demand response capabilities. “The technical requirements for the meters that all demand response customers have for monitoring and metering must also be aligned with the services required,” he says. Whether or not customers are able to adjust their demand is another crucial consideration, adds Russo. “Where we have customers with peaking profiles, or short, high level peaks, it can make sense to use demand response and monetise flexibility,” he explains. “But if you have a customer with flat, base-load consumption it becomes more difficult. These customers are used to taking power from the grid in a steady way and they are not able to change demand without having an impact on production processes.”
Fast-frequency response
Most demand response markets are not yet fully automated, says Russo, and power usage must typically be adjusted in a matter of minutes after receiving a text message or a phone call from a system operator or aggregator. With digitalisation, however, new opportunities for demand response open up. In Australia and New Zealand, demand response providers are already supplying fast frequency response services required within the space of milliseconds. “The duration of the response might be in minutes rather than hours, but this service is also quite useful to the system and can be leveraged as long as everything is automated and the level of digitalisation is very high,” states Russo. “Fast response demand response will become more valuable and profitable with a larger share of renewables.” Demand response efforts have largely been concentrated on the aggregation of demand from larger industrial and commercial power users and some industry players see the aggregation of residential demand as the next frontier. Some companies, like Tiko in Switzerland, are already offering their services as an aggregator to households. Smart household appliances that can automatically adjust demand in response to price signals are essential to applying the aggregator concept to retail customers. The IEA envisages almost one billion households and one billion connected appliances participating in demand response programmes by 2040. Milborrow is among those who believe that the idea of smart energy systems is a “bit oversold” but nonetheless can make an important contribution to demand management. “Behind it lies the idea that part of demand can be controlled and, if you have better control over demand, that will improve the overall control of the system and minimise overall costs,” he says. And that could help system operators ensure that demand and supply continue to intersect in a smooth and cost-effective way.
TEXT Heather O’Brian