The VPP consists of tens of thousands of sonnenBatteries throughout Germany, states sonnen, which are intelligently controlled and can be used as large-scale storage.

The company hopes to reach the 1GWh mark in the coming years, providing a “decentralised buffer storage” that can be used to balance supply and demand on the electric grid, stated the company in a press release.

sonnen is calling the milestone a new standard “in the digital networking of private households and renewable energies”.

Previously the title of ‘Europe’s largest VPP’ was claimed by Elisa earlier this year in February, when the telecommunications company was awarded a grant by the Finnish government for development of a 150MWh VPP.

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The sonnenVPP is currently providing capacity, for example, to compensate for frequency fluctuations (primary control power) in the transmission grid or to participate in electricity trading on the exchange.

According to the company, the system can shift the time at which solar power is fed in so that it is compatible with the grid and, for example, the midday peak is stored by PV systems instead of adding to congestion.

Customers within the VPP also have access to services via intelligent electricity contracts such as sonnenFlat and receive a share of the proceeds.

“The energy transition must not get stuck in the power grids. With our virtual power plant, we have an instrument for intelligently integrating PV systems, e-cars or heat pumps into our power grids. Our power plant is already in people’s homes and doesn’t need any additional space,” stated Oliver Koch, CEO of sonnen.

After proof of concept within the transmission system, sonnen hopes to use the VPP to offer grid stabilisation services in the distribution grid, where bottlenecks from new PV systems, e-cars and heat pumps are already a concern.

Added Koch: “Currently, many processes in the power grids are not yet digitised or regulated accordingly, so that we are far from exploiting the potential of our technology. However, we are doing valuable pioneering work here, e.g. with our own smart meter rollout.”

Sonnen began a smart meter rollout for its customers in 2016 and in May this year announced an acceleration of rollout in Germany alongside Solandeo, a German energy equipment and solutions provider.

The acceleration is an extension of their collaboration and will see the installation of a further 10,000 intelligent metering systems (iMSys) to sonnenCommunity, an independent energy community.

Fully acquired by Shell in 2019, sonnen also operates virtual power plants in the USA, Australia and Italy. Earlier this year saw company join the VP3 alliance in the US, which hopes to develop and scale up VPP technology.

The announcement also included more than $5 million in project awards under the third round of the challenge.

Modernising the electric grid enhances reliability and resiliency in response to a changing climate, optimises the transmission of power and is intended to support New York’s Climate Leadership and Community Protection Act goal to achieve 70 percent renewable electricity by 2030.

“With the increasing number of extreme weather events in New York and across the country, we are working hard to modernise our electric grid and support the development of technologies that will improve reliability,” Governor Hochul said. “By making our grid smarter, more flexible and cleaner with the use of renewable energy, we can ensure the reliability of our energy system, reduce emissions and create a more sustainable future for New Yorkers.”

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Administered by the New York State Energy Research and Development Authority (NYSERDA), through round four, proposals are sought from single or team providers including researchers, product vendors, asset managers and consultants to develop or demonstrate advanced technologies that will support a reliable modern energy transmission and distribution system. Projects must also advance reduced energy costs and greater quantities of renewables integration, while helping the State meet its climate goals.

Up to $3 million per project is available to address high-priority grid technologies including:

• Improved transmission utilisation
• Operational situational awareness
• Distribution Energy Management Systems (DERMS)
• Inverter-based resource integration
• Power electronics
• Grid modeling
• Data analytics
• Artificial intelligence/machine learning
• Protection systems

Projects awarded under Round Three include:

• Clarkson University – $399,000: To evaluate the stability and reliability risks associated with a high voltage direct current meshed network for offshore wind.
• Electric Power Research Institute:
  • $397,000: To investigate the unique situations of the onshore power system as a result of increased offshore wind penetration.
  • $2.3 million: To develop a control management software so solar, battery storage and other distributed energy resources (DERs) can provide further benefits to the grid.
  • $400,000: To study how energy storage deployment can address grid stability issues for transmission and sub-transmission networks.
• New York University – $187,000: To study a methodology for detecting large power transformer defects without disrupting service for maintenance.
• Quanta Technology – $400,000: To study how intelligent power electronic devices located at large renewable generation plants can be used to improve visibility and grid operator situational awareness.
• Switched Source – $1 million: To demonstrate a power electronics device’s ability to increase renewable hosting capacity and improve the reliability and efficiency of the electric grid.

The Future Grid Challenge offers funding to grid technology companies and research institutions that address challenges ranging from the need for greater real-time system data to incorporating smart technologies and energy storage into power grid planning and operations. The goal of the programme is to foster technologies to enhance resiliency, enable and advance energy infrastructure for the performance needed to achieve the Climate Act goals and ensure reliability of the transmission and distribution system, reducing cost and allowing for faster integration of renewables.

The announcement builds on NYSERDA’s Grid Modernization Program, which will provide a total of $133 million through 2026 to further research, develop, and provide funding for solutions that support the advancement of a smart, modernised electric grid and enable the utility investments necessary for full deployment at scale of advanced technologies for the power grid.

Since 2016, NYSERDA’s Smart Grid program has awarded approximately $65 million under 111 contracts to grid technology companies and research organizations for projects including low-cost, high-accuracy grid sensors, modeling and simulation tools and advanced engineering solutions for more effective optimisation, reliability and resiliency and integration of renewable energy resources.

Originally posted by Sean Wolfe on Power Grid.

Under the leadership of special coordinator, Ben Voorhorst, national and regional governments, network operators, Authority for Consumers and Markets and market parties presented the action programme, which aims to upgrade the electricity grid more quickly, stimulate smarter use of the grid with new regulations and encourage more flexible energy consumption.

Upgrading the grid

According to the plan, grid expansion remains the top priority.

The network operators currently invest €3.9 billion ($4.2 billion) annually in the electricity network.

The lead time to expand the power grid can be reduced by several years if network operators, governments and market parties better coordinate their plans and complete procedures in parallel and faster.

Thus, under the plan, each province will provide administrative coordination, for example in the form of an energy board where governments, network operators and industry clusters bundle projects per area and approach them integrally.

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This ensures that permit procedures can be completed more quickly.

Grid operators and market parties will involve each other in planned investments earlier in the process. In this way, the parties involved ensure that expansions of the power grid and the construction and sustainability plans are more closely aligned.

Smarter use of the power grid

By deploying space on the grid flexibly and using the grid less at peak times, more parties can be connected.

Parties involved in the plans want to make ‘rush hour avoidance’ cheaper, introduce flexible contracts and make it possible to share a single connection for wind, solar and energy storage.

Energy storage will also have its own contract conditions, as storage can contribute to resolving grid congestion.

Also of interest:
Is Germany’s grid ready for a renewable net zero?
Monetising flexibility as a fix for grid congestion

Increase flexible capacity

As the Netherlands transitions to a sustainable energy system, it is becoming increasingly important to match energy consumption with local energy production.

Energy producers, industry associations, network operators and governments will help companies with technical support. Financial support is also being investigated.

Provinces and municipalities will start supporting energy hubs, which are local networks, for example on business parks, in which generation, heat, storage and consumption are coordinated. By using energy locally, the national power grid is less burdened.

On the plan, Dutch minister Rob Jetten for Climate and Energy stated: “With this action plan, we are taking important steps on several fronts to solve and prevent problems with the full power grid as much as possible. This is very important if we are to continue making our economy more sustainable at a rapid pace.”

The plan was launched by the country’s network operators, ACM (Authority for Consumers and Market), local authorities, market parties and the Ministry of Economic Affairs and Climate Policy.

Grid2030 was a multi-year open collaborative initiative supported by EIT Innoenergy and Red Eléctrica and promoted by Elewit.

The three companies defined different challenges in innovation to find solutions to the problems of the electrical system as more renewables start to come online. These solutions include improving the system’s efficiency and flexibility, promoting the integration of renewables and optimising the performance and accessibility of assets in the transmission grid.

Entrepreneurs and innovators from public and private organisations, universities, research centres and European businesses participated in the development of the three projects.

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The three projects include:

• Flexible Smart Transformer:
  An initiative of Red Eléctrica, Efacec (Portugal), and Circe (Spain). Grids need more flexibility and components with new functionality in the present energy transition. This project presents a modular prototype that uses power electronics and a transformer with magnetic coupling through a dielectric medium rather than a closed ferrite core and high-frequency switching. The combination of each module’s strong isolation capacity will enable the control of voltage levels and grid stability, which will increase the grids’ sustainability and efficiency.
  
• Reduced Inertia Transient Stability Enhancement:
  Developed by experts from the Supergrid Institute (France), the IMDEA Energy Institute (Spain), and Red Eléctrica, the project’s goal was to increase the electrical system’s flexibility in an environment where non-manageable energies are widely used. As tools for system operation, the project specifically created new stability resources and integrated controls to optimise the behaviour of HVDC-VSC links and storage systems.
  
• Enigma:
  A project between Red Eléctrica and Spanish businesses HI Iberia, Ingelectus, and Prysma, the project saw training for Artificial Intelligence (AI) agents to manage the energy that new renewable plants supply to the grid. The agents learned to respond to potential eventualities while keeping the frequency within the required margins using a single-node grid simulator and reinforcement learning techniques. The findings indicate a different approach to controlling these plants from a disruptive standpoint.

A total of €1.6 million ($1.7 million) was invested in the three projects within the framework of the programme, which had been running for four years.

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Under a five-year agreement, ANRA – which develops integrated airspace, mission management and delivery systems for unscrewed vehicles – will provide the US public power utility with the technology.

It is the hope of the NYPA for the tech to improve their workflow efficiency, fleet management and safety for enterprise air, sea and land robotic system operations.

The mission manager software aims to allow NYPA to manage its robots safely, reducing risk for front-line NYPA employees that otherwise might be exposed to hazardous conditions when using more traditional methods of inspecting infrastructure and monitoring equipment.

According to the NYPA, the programme will help improve shared situational awareness across its enterprise. It will also assist in reducing response time and improving workflows for everyday operations and maintenance projects as well as weather events and other emergency response activities.

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“We are pleased to be able to use systems like the mission management software that will help us meet our VISION2030 strategic goals as we work to help create a more resilient New York powered by clean energy,” stated Brian Saez, senior vice president for Power Supply at NYPA.

“With smart technology like this mission management software, NYPA staff can improve awareness and operational information sharing throughout our enterprise and communications with our stakeholders,” continued Saez.

“We are thrilled to collaborate with an enterprise like NYPA that uses air, sea and land systems that will be integrated, managed and operated with our single software platform,” added Amit Ganjoo, founder and CEO of ANRA Technologies.

“Our background and experience working with the FAA, NASA and Fortune 50 enterprises will help ensure safety of the mission while enabling the technology that ultimately reduces risk for the NYPA teams that work hard and in sometimes potentially hazardous conditions.”

While electric vehicles (EVs) currently account for a very small fraction of the cars on the road, sales are rising and that trend will only accelerate as prices fall and range increases.

This will inevitably impact any business that has an employee or customer car park. Consequently organizations need to consider the impact of EV charging and future EV trends on their energy strategy. This is particularly the case for businesses who may need to install multiple charging or rapid charging infrastructure at their premises.

This article was originally published in Smart Energy International 3-2019. Read the full digimag here or subscribe to receive a print copy here.

Many businesses will be unaware that installing significant numbers of EV charging points is likely to have implications for their existing electricity supply, which may need upgrading to cope with the increased demand.

As car manufacturers strive to reduce EV charging times in order to make the ‘refuelling’ process more akin to that of a conventional car, the power requirements of the chargers are increasing. Early rapid chargers were in the order of 50kW to 100kW; however, the latest generation is already up to 300kW. When contrasted with a typical SME power requirement of 80kW, the scale of the issue becomes apparent. Whilst an SME would more likely install slow charging infrastructure in the range of 3 – 7kW each, in selected circumstances we are already seeing some organisations planning for rapid charger installation. In one particular instance, rapid charging will necessitate a capacity upgrade some 30 times that of the current supply. Such an upgrade is not a paperwork exercise and will require major network reinforcement, at significant cost.

Those installing slow charging are not necessarily immune from such issues. Whilst a single 3kW charging point may have little impact on a premise’s electricity supply, 100 such charging points will. Even if the necessary capacity is present, the next issue becomes the electricity consumed. A single 3kW point charging an EV for eight hours will consume 24kWh, currently costing around £3 a day. When a single employee asks for an EV charger to be installed, a business may well be happy to absorb this energy cost. When half the workforce has an EV, will that same business be happy to absorb the cost of firstly installing the charging points, and secondly the energy consumed?

If that one employee becomes 50, the daily electricity cost rises to £150 and over the course of a year that cost is over £35,000. It may be easy to think that the scenario described above is a long way off, but the automotive market is shifting.

Governmental policy and simple economics will see increased EV adoption rates as vehicle costs fall, choice widens, and battery range improves. Some in the industry are already citing that the current crop of ‘affordable’ EVs have already achieved cost parity with their fossil fuelled brethren, when purchase/lease, operating costs and residual values are considered.

Consequently, it is paramount that any business with a staff or customer car park has an EV policy that considers: whether EV charging will be offered and, if so, the number of charging points and power of each; any impact on the existing electricity supply; who incurs the energy cost; and ultimately, if energy costs are to be recovered, how this will be achieved.

Businesses acting now will not only be better prepared for the inevitable question from either a staff member, visitor or customer of ‘Where can I charge my car?’ but may find competitive advantage in deploying EV charging infrastructure. Furthermore, some businesses, especially those that install significant numbers of EV chargers, may even be able to derive an additional revenue stream from applying a margin to the energy supplied, or providing Vehicle to Grid (V2G) services in the future.

Will the grid cope?

Given the increasing demands EVs will place on the local distribution, national transmission and generation infrastructure of the electricity system, there is a very strong possibility that the grid (or aspects of the network) won’t keep pace with the ultimate rate of EV adoption. Consequently, we are likely to see the evolution of smart charging. Instead of charging as soon as it is plugged in, the EV or charger will examine parameters relating to local and national demand, price, signals, time of day, the customer’s charging preferences and battery charge state, and then decide on the most optimal time to charge. Customers who are most flexible around when this happens will probably pay a lower price for the electricity, whereas people who want to be able to recharge their vehicle immediately will be able to do so but at a higher cost.

Mobile battery storage

A natural extension of smart charging will be Vehicle to Grid. V2G describes a system whereby plug-in EVs, including battery electric vehicles (BEVs), hydrogen fuel cell electric vehicles (FCEVs) or plug-in hybrids (PHEVs) have the ability to export electricity to the utility provider. With the EV owner’s consent, a utility provider could effectively draw electricity from V2G connected cars. Owing to the variable output of all sources of electricity generation, especially renewables, the operators of the grid are increasingly looking for providers of balancing services organisations that can either absorb power when generation outstrips demand, or supply power when demand is higher than generation. The batteries in EVs are ideal to provide such balancing, assuming power is able to flow in either direction.

As EVs become more mainstream, the collective capacity of their batteries and ability to store electricity will be huge. Significant numbers of EV owners who allow access to even a small percentage of their EV’s battery will collectively provide an enormous balancing resource that has a significant value.

As with smart charging, V2G will be largely driven by financial incentive – allowing access to a small percentage of the EV’s battery will probably result in the vehicle owner being directly compensated or given preferential energy rates for charging. Such a dynamic system that includes smart charging and V2G will also bring with it operational challenges. EVs will not always charge at the same location through the same electricity supply. Consequently, how the benefits of smart charging and V2G along with the actual cost to charge are apportioned between the vehicle owner and the owner of the charging point and electricity supply are currently unclear.

To achieve smart charging, V2G and appropriately apportion the benefits and costs, the quantity of data analysis and the financial decisions that will need to be taken in real-time will likely necessitate a fully automated process. It will require extensive telemetry throughout the electrical distribution system and in the EV, along with real-time information relating to the electricity price, grid frequency, predicted generation availability, weather data and EV owner preferences.

From an EV owner perspective, the process will need to be sufficiently simple and ideally visual, to allow them to see the status of the EV at any given time and feel in control of the process, regardless of the complexity behind the scenes. In much the same way as the online portals provide customers with complete oversight of their energy status, from simple overview of use and spend to complex analysis, EV owners will need similar oversight of energy use, cost and benefit.

In all likelihood we envisage an app-driven system where the EV owner will set basic parameters regarding when they want to use the vehicle and the range they require, and the system will operate to ensure the vehicle charges sufficiently at the lowest cost by charging and discharging as required. Alternatively, an override would allow maximum, instant charging at a higher price for the faster availability.

 Evolution

There is currently a lot of discussion and enthusiasm for behind-the-meter battery storage to provide balancing services; however, this vocal enthusiasm in not seemingly translating into many installations.

Furthermore, we suspect that when EVs and particularly V2G become mainstream, the requirement for standalone storage will disappear altogether. Currently with behind-the-meter battery storage, a business case needs to be built, weighing the battery installation cost against the return from the provision of balancing services. With EVs, the battery purchase has been made anyway as part of the EV (or leased as part of the EV), so using an EV battery for motive power and balancing services would appear to be a much more viable option than investing  in stationary batteries for a single purpose. While the battery capacity of a single EV is likely to be much smaller than a behind-the-meter battery, and only a small proportion would be accessible for discharge, the number of EV batteries available will, in time, quickly eclipse the total availability of standalone batteries.

If EV adoption accelerates at the pace many believe, and V2G follows suit, the market for behind-the-meter battery storage could quietly die before it has the chance to become mainstream. The wide-scale adoption of EVs will bring challenges to the electrical infrastructure; however, in many regards, the flexibility afforded by the batteries will in itself go some way to solving those challenges. Furthermore, as electricity generation turns increasingly to intermittent renewables and away from conventional, dispatchable, fossil-fuelled generation, the collective battery capacity of EVs will be key in maintaining a stable, greener, grid in the future.

What we’re starting to see is the tip of a rapidly approaching iceberg. Issues around EV infrastructure and strategy are already impacting some customers and the wider business community needs to be conscious that they will, inevitably, impact them too. Just because you can’t see hundreds of EVs when you look out of the window today doesn’t mean that the rise in their adoption is a long way into the future. It is already happening and there is a real danger that organizations who don’t start planning their EV energy strategy will get left behind .

About the author:

Adam Pigott is engineering manager for Kinect Energy Group.
Based in London, and with 19 years’ experience working in the energy sector, Pigott heads up the engineering arm of Kinect Energy Group’s sustainability team, delivering physicalenergy, cost and carbon reductions to Kinect’s customers. He specialises in the delivery of measured energy savings, frequently without the requirement of investment in new equipment.

Technologies including local renewables, battery storage, electric vehicles (EV’s) and demand-side management will be explored.

The project, expected to run for three years, was granted £13.8 million by UK Research and Innovation (UKRI) as well as £26 million of private partner-funding.

Project LEO aims to replicate and trial demonstration system operator models being researched by the UK government, industry, and the country’s energy regulator via the Energy Networks Association’s Open Networks Project.

The trial will also look to balance real-world demand and supply, whilst testing markets and investment models in an effort to glen the benefits of increased flexibility.

The Oxfordshire council has already started energy-saving street lighting, waste reduction and solar school projects, which, along with the levels of constraint on the grid in the area, and the forward-thinking approach of both local authorities.

Project partners include Scottish and Southern Electricity Networks (SSEN) as project leaders, in partnership with the local city and county councils, the Universities of Oxford and Oxford Brookes, EDF Energy, Nuvve, Low Carbon Hub, Open Utility and Origami Energy.

The new project will support Oxfordshire’s target to reduce city-wide emissions by 40% by 2020, which means it must generate 58% of its electricity demand from renewable sources.

Councillor Tom Hayes, board member for a Cleaner and Greener Environment at Oxford City Council said: “Project LEO will return power to the people so that we can generate clean energy for our own neighbourhoods. By creating opportunities for communities to trade the energy they generate, use and store at a local level, we hope that Project LEO will empower people, companies and local areas to build an energy system that works for people and planet.”

The utility has successfully completed a gamification trial whereby households were incentivised to reduce consumption at times of high demand through a mobile game.

More than 2,000 customers competed for cash prizes during the trial by turning off unnecessary appliances including televisions, washing machines, and lights in exchange for points – the energy saved as a result was converted into points, which in turn, increased their chances to win cash prizes, with up to £350 available each month.

Players saved an average 11% at 305W, with some dropping as much as 4.9kWh in usage through the game.

The company serves eight million customers across 3.9 million homes and businesses in Britain’s North East, Yorkshire and northern Lincolnshire, and have stated that mobile games have proved an important tool to manage power demand and reduce customer billing.

The company says better grid balancing technologies will be increasingly important as the widespread adoption of renewables such as rooftop solar, electric vehicles (EVs), and domestic battery storage gets closer.

Northern Powergrid, Newcastle University and GenGame have entered into a £400,000 joint project with Ecotricity and EnAppSys to explore how mobile games can incentivise EV owners to use their vehicles to support the grid via charging technologies.

Andrew Webster, project manager at the utility said: “By making comprehensive findings widely available – including our trials, errors and triumphs – we hope to jump start other gamification programmes for operator colleagues and play our part in benefiting energy customers across the whole country, not just our patch.”

The demand spike has been caused by cold weather and insufficient output from solar generation systems.

Chubu said in a statement that it had received up to 1.05GW of power from the other utilities.

“We are also ramping up one of our coal-fired power plants and one of our LNG (liquefied natural gas) power stations as electricity demand for heat increased due to lower-than-expected temperatures and cloudy weather caused lower-than-expected output from solar power,” a spokesman at Chubu Electric said.

The power providers include Tohoku Electric Power, TEPCO Power Grid, a unit of Tokyo Electric Power Company Holdings, Hokuriku Electric Power, Hokkaido Electric Power, Chugoku Electric Power, Shikoku Electric Power and Kyushu Electric Power, he said.

“We may start up some old fossil fuel power plants that had been mothballed to meet higher demand,” the spokesman said.

The last time the company needed power from other utilities was in February 2017.

The park is a 50 square kilometer energy city project to position Saudi Arabia as a global energy, industrial and technology hub.

The energy city will house approximately 300 industrial and service facilities.

The city will be developed in partnership with global investment and technology firms.

Phase one of the project will result in $1.6 billion in investments and will be completed by 2021.

Once operational, the park is expected to add $6 billion to the country’s annual GDP and create up to 100,000 jobs.

H.E. Khalid A. Al-Falih, minister of Energy, Industry and Mineral Resources, said: “SPARK is one of the country’s most ambitious projects, affirming the Kingdom’s commitment to Vision 2030 by creating thousands of high-skilled jobs, serving as an economic catalyst and advancing Saudi Arabia’s strong position in the global energy sector. The energy park’s unique value proposition makes it an ideal destination for companies looking to invest in the thriving Saudi Arabian energy services market.”

The integrated energy company will bring together businesses wanting to participate in the project.

International firms already signed to the project include Schlumberger; Baker Hughes GE; Halliburton; Oilfields Supply Center; Emerson; National Energy Services; Valco; Huatong; Borets; and Al-Rushaid Group

The investment funds the design, manufacturing, provision and testing of some 990 Cast Resin Distribution transformers with LV Smart Meters.

The contract has been awarded to various leading international transformer manufacturers.

The project falls under efforts by the utility to expand its energy distribution network and provide its services according to the highest international levels of efficiency, reliability, and availability.

The transformers will be supplied through to July 2019 to increase the capacity, efficiency, and reliability of the electricity distribution network in Dubai

DEWA says the project will ensure a continuous and stable supply of power to all customers.

“DEWA continues to implement vital development projects in line with its vision, which is aligned with federal and local strategies. These include the UAE Vision 2021, the National Agenda, the UAE Centennial 2071, Dubai Plan 2021, and the Smart Dubai initiative,” said HE Saeed Mohammed Al Tayer, MD & CEO of DEWA.

“We have made significant achievements and excelled in our efficiency, sustainability, and optimal management of infrastructure investments, and smart network operations. In all our operations, we focus on availability, reliability, and efficiency in our electricity and water services,” added Al Tayer.

The solutions provider will provide the utility with services including programme management, marketing, IT and customer care support for the demand response initiative.

The services will include integrating the utility’s distributed energy resource management system with consumers’ programmable communicating thermostats. ICF will be responsible for the installation of the thermostats in consumer homes.

The solution provider has also been tasked with registering 40,000 new customers in the demand response programme.

David Pickles, SVP at ICF, said: “The demand response program will permit the utility to use recent technology advancements to drive cost-effectiveness, to provide localised benefits to the grid and to strengthen the relationship with its customers.”

“The success of these technologies relies on utilities’ ability to distill complex offers into a clear, motivating call-to-action for customers—one that offers a seamless enrollment process and superior customer communication and support, year after year,” added Jeff Adams, SVP at ICF.

ICF manages over 150 demand side programmes for more than 50 utilities across the US over the past ten years.