Moving the Virtual Power Plant vision to reality
Rapid changes in electricity demand, information technology, regulatory mandates, and customer expectations have spurred forward-thinking leaders in the utility industry to define a new vision for modern electric system architecture and operations. The working title for this new vision is the Virtual Power Plant (VPP).
The Concept. The VPP integrates the operation of supply- and demand-side assets to meet customer demand for energy services in both the short- and long-term. To match short-interval load fluctuations, the VPP makes extensive and sophisticated use of information technology, advanced metering, automated control capabilities, and electricity storage. The VPP concept also treats long-term load reduction achieved through energy efficiency investments, distributed generation, and verified demand response (DR) on an equal footing with supply expansion. Thus, this approach extends the boundary of utility capacity investments through the meter, with its expanding communication and control capabilities, all the way to customer-side equipment.
The Opportunity. The principal strategic objective of the VPP is to enable the utility to supply customers’ energy service needs, while minimizing the cost and risk associated with investment in peak generation capacity, base-load plants, and transmission facilities. The ability to couple and co-optimize energy resources in real-time and shape the load, also promises to improve system reliability by adding capability to manage transmission and distribution congestion. Finally, the VPP approach will significantly reduce carbon emissions by limiting the need for peak generation and facilitating the orderly integration of intermittent renewable resources into grid operations.
Although the VPP represents a significant new direction in utility planning and operations, many of its key elements are already in place, and penetration levels are growing as our energy technology moves toward distributed generation and electric storage. An important capital component is the advanced metering infrastructure (AMI) and related control systems that make up the smart grid. Utilities in all 50 states have deployed customer meters with interval usage monitoring, two-way communication, and control capabilities. The Federal Energy Regulatory Commission (FERC) projects that 80-140 million customers representing up to 450 GW of load will be served by AMI in 2019. These systems offer utilities the means to achieve the often conflicting goals of enhanced capital utilization, lower financial risk, improved reliability, and reduced environmental damages.
The Challenge. Despite this potential, most regulatory commissions have withheld investment authorization of full AMI roll-out pending persuasive demonstration of net social benefits. While operational efficiencies offset some costs and can result in positive business cases, nearly all benefit-cost analyses of AMI find that if these systems are also utilized to increase customer energy efficiency and provide load management, demand response, or price response, the business case is greatly improved. Achieving these benefits requires engagement with an informed and willing customer.
The technologies, service offerings, business processes, and organizational designs envisioned for the VPP will enable utilities to meet the many challenges of fully integrating demand-side resources into the design and operation of electric systems. Foremost among these, utilities must convince and enable customers to invest in long-term demand reduction and to participate actively in short-term load control. AMI and other technology resources provide capable and flexible channels of communication among energy suppliers, their customers, and equipment on both sides of the meter. Now it is necessary to find the most effective content for those channels.
Applications of the Virtual Power Plant
Approach
Current Application: Automated Demand Response (Auto DR).Auto DR is an important application of the VPP approach that is already well-established in the commercial and industrial market. In an Auto DR project, a customer, typically supported by a controls and information technology vendor, installs equipment that enables demand reduction in response to wholesale price fluctuations or system reliability needs, signaled by a utility or independent system operator. The customer is compensated for demand reduction performance and may direct some of that compensation to third parties for ongoing support. Controls industry giants, have entered this market as full-service providers, as have new IT-oriented competitors. These companies typically provide a suite of services including design of control installations and telemetry, remote management of energy equipment, management of response to calls for demand reduction, and fulfillment of technical and administrative requirements, such as monitoring and verification of performance.
Auto DR is becoming an important resource in several jurisdictions and markets. For example, active demand response resources account for 1,025 MW or 3 percent of total installed capacity requirements cleared into ISO New England’s Forward Capacity Market. A significant portion of this capacity is provided by firms such as those previously mentioned. However, it is not possible to assess from market and program records, the degree to which automated response systems—as opposed to occupant actions—actually control building operations during demand response events.
In the residential sector, utilities have long used one-way direct load control of central air conditioners, water heaters, and pool pumps to reduce peak loads in the face of emergency conditions. As of 2006, 232 such programs were in operation and controlled over 6,000 MW of load. As smart grid-enabled appliances and controls become more widely available and less expensive, the scope of residential Auto DR programs is likely to increase. For example, customers receiving dynamic price signals may be able to choose price thresholds at which their thermostat settings would be automatically adjusted, or water heating or refrigerator operation would be automatically reduced.
Emerging Application: Microgrids.The emerging concept of the microgrid builds upon the technical and commercial concepts evolved in Auto DR. Owners of large campuses, such as hospitals, universities, and military bases, have begun to explore the economic advantages of an integrated operation of loads, generation, and storage located on their side of the electric service entrance. This approach enables the owners to realize the full financial benefits of efficiencies in energy supply, such as combined heat and power (CHP) and renewables, while pursuing institutional mandates in regard to emission reductions and avoidance of service interruptions. Storage and distributed generation facilities developed for internal use can also be made available to the electricity distribution company for emergency load response, price response, and capacity. Microgrids are likely to play an important role in unlocking the huge potential for clean distributed generation and storage—estimated with conservative assumptions at 50 GW by 2025—by aggregating benefits to a sufficiently high level, so it becomes economical for owners to undertake the required facility planning and management responsibilities.
Emerging Application: Regulation Ancillary Services from Electric Vehicles.Many in the electricity and automobile industries have identified charging of electric vehicles and plug-in hybrid electric vehicles (PHEV) as an end use that can help even out load shapes and improve capacity utilization. The time needed to recharge an electric vehicle will be 2–5 hours, but it will be plugged in for 10–15 hours per day. With this schedule, the storage embodied in car batteries can provide a broad range of benefits to grid operators and customers if properly aggregated and controlled.
Most plug-in vehicles will be equipped with Internet-enabled communications. In a VPP environment, drivers will automatically initiate Internet contact with a load aggregator when they plug in. The aggregator will simultaneously monitor conditions on the grid and the status of all vehicles plugged into its system. For each vehicle, the aggregator will know the location, the energy required for the next charge, the maximum and minimum recharge power draw, and the customer’s schedule for the next trip. With this information, the aggregator can control the pace of charging and discharging the entire fleet to provide regulation ancillary services, with dispatch modulated every four seconds.
Scenarios developed by Google suggest that a fleet of 3.2 million electric vehicles could provide sufficient regulation power for the entire PJM control area, which contains roughly 22 million households. The capability to provide fast, accurate responses to power demands could be used to provide “generation-following” regulation for the output of wind and solar resources.
Getting There from Here
So where do we stand in the development of the Virtual Power Plant? What are the next critical steps that must be taken to put the VPP in place and to realize its benefits?
AMI, related distribution controls, and end-use systems, such as smart vehicle chargers and smart appliances, will form the physical basis of the VPP. The structure that customers see, feel, and touch will consist largely of service offerings and business processes required to support those offerings. The experience of energy efficiency, demand response, real-time pricing programs, and the retail electricity industry accumulated and documented over the past 20 years provides a rich source of insight to guide the development of these offerings.
The third volume in KEMA’s Utility of the Future series examines this record and its implications for evolving utility operations in depth. Highlights of lessons learned in regard to customer value proposition and design of service offerings include the following.
Getting the customer value proposition and product design right. None of the actual mechanisms of the VPP can function without the active participation of electricity customers. Even for mechanisms in which load response is automatic, the customer must agree to install and purchase the necessary equipment and to abide by the operating rules of the relevant programs and markets. For dynamic pricing to be effective, with or without enabling technology, customers must understand how their equipment operating choices affect their bills under these prices. Adequate financial returns on investment in VPP will require a much higher level of customer participation than energy efficiency, demand response, and voluntary pricing programs have experienced to date.
The Need for Co-Optimization.Larger commercial and industrial customers have increasingly advanced building energy management systems or, indeed, industrial process management systems capable of responding to demand response control signals and/or real-time prices, and capable of providing information and validated response data back to aggregators and market operators. More sophisticated building management systems are able to manage on-site thermal storage. They can also use the building itself as a source of thermal storage, for instance, by "pre-cooling" the building in early morning hours to enable reduced energy consumption later in the day at peak hours.
In the future, these kinds of facilities will have the potential to combine building and process energy usage, on-site generation, thermal and electric storage, and even electric vehicle charging to co-optimize all resources against forecast weather conditions, basic usage demand, and energy market prices, so as to minimize costs and even maximize revenues from market services, such as ancillary services. One of the keys to achieve high Renewable Portfolio Standard (RPS) goals will be the usage of DR as a form of system reserve, real-time dispatch, and other ancillary products. These services require a quick response (< 5 minutes today) and "certainty" in the response provided. Advanced building systems can provide continuous updating of what is available and factor the potential revenues from ancillary service provisions into the co-optimization.
Laying the Foundations for the Virtual Power Plant.Utility executives, policy makers, and regulators at the federal and state levels mostly agree upon the barriers to broader integration of demand-side resources into grid operations and the steps needed to overcome them. The following points identify key elements of a policy and regulatory agenda to support the development of the VPP:
Establish markets and price mechanisms to guide the development and deployment of demand resources wherever possible.
Develop consistent, long-term customer incentive and technical assistance programs to support the development of key elements of the VPP.
Within jurisdictions, coordinate the marketing and operation of demand response with energy efficiency programs conducted by system operators, utilities, and government agencies.
Develop and disseminate frameworks for consistent inclusion of demand-side resources in forecasts used for supply planning.
Future Outlook for Utilities and Their Customers. The utility business model, functions, and relationship with the customer change significantly with energy resources tied into a tightly coupled real-time control regime. Furthermore, the utility’s overall role in regard to management of the energy grid will change as distributed generation and storage technologies evolve.
This article is excerpted from KEMA’s white paper “The Virtual Power Plant”, which summarizes concepts discussed by KEMA and industry experts participating in the April 2010 KEMA Energy Innovation Forum.
The full paper, including charts and graphics, is available for download.