The past few years have brought decades worth of change to electric utilities. An increasing fraction of supply is coming from intermittent sources like solar and wind. Energy storage technology has become economically viable and has seen widespread deployment. And the industry as a whole is grappling with what seems like insatiable new demand from data centers and artificial intelligence (AI). Virtual power plants (VPPs) are a high-value addition to the supply portfolio that can help utilities navigate and respond to change. VPPs enable utilities to transform the rising number of distributed energy resources (DERs) connecting to the grid from a source of complexity and potential difficulty into a powerful asset that can help address a variety of challenges. VPPs aggregate DERs to increase effective capacity, respond to peak demand, and provide flexibility to the grid. Implementing a VPP in a way that maximizes its value is critical. Like any asset, a VPP requires investment in a system that should remain effective 10 or 15 years from now. But how can utilities ensure long-term value in the face of accelerating change? Trying to predict what your needs will be next year is difficult enough, much less predicting needs a decade or two in the future.
Luckily, you do not need to predict the distant future to map out a VPP strategy. By making flexibility a guiding principle, utilities can future-proof their investment. Consider the following three key elements of VPP flexibility. Frequency of Participation. For many utilities, previous experience with demand response programs strongly influences the way they envision VPPs. It is natural to connect the two since one of the major benefits of a VPP is its ability to address peak demand situations. But demand response programs have historically focused on encouraging customer participation by limiting impact and inconvenience. A typical demand response program might assure customers contractually that they will be asked to participate no more than five days each summer and for no more than two or three hours at a time. Utilities may be tempted to design VPPs along the lines of demand response programs by artificially limiting the frequency of use to encourage participation. But rigid tariff structures will likely tie the utility’s hands in the future. What if the peak demand situations happen far more often in the future? And what if it turns out that some residential and commercial customers prefer to offset the cost of their DERs by participating far more frequently in exchange for higher compensation? Some businesses may even want to build DER revenue into their business plan by negotiating as many days of participation as possible. By building flexibility into how often the VPP can be deployed and how long it can be deployed for, and by making these parameters variable, utilities can turn VPP solutions into a customizable platform that can adapt to changing grid needs and changing customer preferences. Type and Scale of DERs. The deployment of DERs is scaling in unpredictable ways that require utilities to be adaptable. Another way utilities can create a VPP strategy that works for the long term is to build in flexibility around the types and quantities of DERs that may be connected to the grid. DER growth tends to occur in a splotchy manner. One person’s rooftop solar installation can lead to many neighborhood copies and an overloaded substation transformer on sunny days. In some geographies, electric vehicles (EVs) have already become dense enough that they can offset the loss of a large generator in an emergency and help avoid curtailment of solar generation at peak times. And major users of grid capacity like data centers and electrified fleets may soon end up being sources of grid capacity as well through energy storage or onsite generation. Utilities should build flexibility into their VPP strategy by avoiding rigid expectations around the future makeup of VPP assets and their growth trajectory. Your Operations. In the past, electric utilities operated in two distinct realms: transmission (typically at the regional level) and distribution (typically at the local level). Transmission operations focused on seeking balance between demand and supply across the utility’s entire grid and across grids operated by other utilities, managing and maintaining transmission lines and other related activities. Distribution operations focused on managing demand at the local level, monitoring for outages, managing switching and reroutes, and maintaining distribution infrastructure. With the rise of VPPs, utilities are beginning the process of introducing a third operational realm. This new realm encompasses assets not owned or maintained by the utility. These assets can be turned up, turned down, and turned on and off in ways that are quite unlike traditional grid infrastructure. This new operational domain introduces a promising and highly flexible tool that can complement transmission and distribution, improving efficiency and reliability while lowering overall system costs. The way each utility builds and deploys its VPP will be unique and is likely to evolve over time, influencing the way that transmission operations and distribution operations function in the process. Because these three areas of operations will influence one another in ways that we cannot yet predict, it is critical to avoid designing a VPP with a rigid model for its role alongside transmission and distribution operations. Building flexibility into operational models helps take advantage of efficiencies and benefits that are impossible to predict today but that will become clear over time.