Beyond load growth: The EV managed charging opportunity for utilities March 23, 2017 | By Erika Myers I have recently been talking with a range of utility staff about how to best integrate electric vehicles (EVs) into their planning and program efforts — a topic that often sparks both interest and uncertainty. In an era of flat to declining load growth, many utilities see EVs as a strategic opportunity — demand growth on wheels — but don’t know how to most effectively insert themselves into the emerging electrification of America’s transportation fleet. As a first step, many utilities have commissioned EV forecasts to get a sense of the likely penetration levels in their service territories. However, based on my own experience developing such forecasts, I can say they don’t offer the level of granularity that utilities need – for example, the number of vehicles concentrated on a particular feeder or connected to a specific distribution transformer. We can’t assume that these vehicles will be evenly dispersed across a service territory. Rather, we know from real-world experience that electric vehicles — like rooftop solar installations — often are clustered in a particular neighborhood or even on a single block. The dynamics at work here could be partly peer pressure — “keeping up with the Joneses” – but more likely basic demographics — income, homeownership, education level — which, some studies suggest, are the key indicators of an individual’s propensity to buy an EV. Further, EVs can create risks for utilities, such as peak load increases, transformer and substation impacts, or the new phenomenon of “timer peaks,” an inadvertent result of time-of-use rates. The problem here is that even though time-of-use rates have helped shift charging hours to preferred times of the day — late evening and early morning hours — customers often schedule their vehicles to begin charging at the moment off-peak rates begin, resulting in sharp load ramps. Managed charging vs. V2G The challenge for utilities is to find a way to distribute these charging events across the full span of off-peak hours, or even better, to time vehicle charging for periods of high renewable energy production — mid-day for solar or night-time for wind. Managed charging – also called V1G, or intelligent or smart charging — allows a utility or third-party to remotely control vehicle charging by turning it up, down, or even off to better correspond to the needs of the grid, much like traditional demand response programs. Managed charging is different than vehicle-to-grid (V2G) dispatch, that is, the use of a plugged-in EV with available charged battery capacity to backfeed power to the grid. While V2G has been tested in a small number of pilots, a number of technical and regulatory issues need to be overcome before it can be widely and effectively used. While managed charging also faces some barriers, solutions are in process and could help prepare a solid foundation for V2G. Using managed charging as an effective grid resource — with benefits for customers and utilities — could represent a compelling opportunity for utilities. As of February 2017, more than 580,000 EVs have been sold in the United States, representing approximately one terawatt-hour (TWh) of annual electricity consumption. According to Bloomberg New Energy Finance, EV power consumption is projected to increase to approximately 33 TWh annually by 2025, and 551 TWh by 2040. Given the projected growth in EVs, and the increasing need for flexible grid resources, the Smart Electric Power Alliance (SEPA) is seeing more and more utilities evaluating managed charging. In SEPA’s 2017 Utility Demand Response Survey, 69 percent of respondents indicated that they are planning, researching or considering demand response programs that integrate EV managed charging, compared to 20 percent that, at present, have no interest. Figure 1: Utility Interest in Electric Vehicle Managed Charging Demand Response Programs Source: Smart Electric Power Alliance Pilots and bottlenecks Certainly, utilities have been among the most innovative field testers of managed charging technologies, experimenting with different vendors and technology types, and achieving a certain degree of success. San Diego Gas & Electric’s day-ahead, price-varying EV rate reflects circuit and system conditions and the changing price of energy throughout the day. Through a user-friendly phone app, EV drivers can save money by setting vehicle charging times to low-priced hours of the day. Southern California Edison used a workplace charging pilot — leveraging afternoon peaks and load reduction strategies — to learn more about driver behavior and responsiveness to pricing signals. The program included a high price option allowing users to have no charging disruption; a medium price allowing for peak demand curtailment from a faster Level 2 to a slower Level 1 charging rate; and a low price allowing drivers to be entirely curtailed during a demand event. One of the findings of the study was that drivers need maximum optionality, meaning if they need to charge at certain times, they want the ability to opt out. Pepco’s pilot program reduced chargers from a Level 2 to a Level 1 rate of charge for an hour during a demand response event and provided opt-out capabilities for customers. When assessing the economics of the pilot, Pepco found that that the ongoing costs of the communications link were too expensive. Identifying a cheaper solution would increase the viability of future projects. The Pepco pilot points to some of the technical bottlenecks for utilities looking at managed charging, including network communication and equipment interoperability. As with other grid modernization technologies, such as advanced metering infrastructure and smart thermostats, the key to wide deployment of managed charging is finding an inexpensive, reliable way to send communication signals. The signals a utility would send to EVs and vehicle chargers combine messaging, or application, protocols (e.g., OpenADR 2.0, OCPP) and transport layer protocols, also known as network communication interfaces (e.g., WiFi, cellular). The difference is that the messaging protocol contains the instructions – don’t charge until after midnight — while the network protocol ensures a message gets from point A to point B, but does not provide any instructions or guidance as to behaviors of the receiving devices. One of the main issues to date is deciding on a uniform messaging protocol amongst a large field of open and proprietary protocols by different vehicle and charging equipment manufacturers. The development and use of appropriate and uniform communication standards is the most effective way to move the needle on managed charging. Utilities are the nexus Though the U.S. EV market is still nascent, utilities need to be involved and should begin planning now to help shape the relevant policies, regulations and standards for the future. As shown in Figure 2 below, utilities have a central role to play as a nexus for stakeholders in the EV space. With their deep knowledge of customer interests and expectations, utilities can proactively communicate the needs of the customer and the grid to vendors — including EV and charging equipment manufacturers — and recommend the most efficient and cost-effective strategies for common communication and other interoperability standards. Figure 2: Utility Role in Managed Charging Source: Smart Electric Power Alliance Equally important, despite the potential benefits of managed charging, getting consumer buy-in for these programs may require utilities to develop a range of outreach and engagement strategies. After all, most consumers buy an EV not to improve grid health, but to meet their transportation requirements and, in some cases, environmental values. Utilities will need to keep customer considerations front and center by developing programs with user-friendly features, flexibility and incentives. A customer-centric approach might include opt-out and override features, messaging and alerts based on customer preferences, smart phone functionality for control and management, and rewards, rebates and other perks to keep customers happy and engaged. Managed charging is only one of many distributed energy resource (DER) technologies that can be leveraged to develop a smarter, more reliable grid. As consumers evolve to become prosumers, utilities must keep pace with their demands and expectations through experimentation and continual self-assessment of the traditional utility business model. Despite some initial growing pains, managed charging could prove to be a gateway for consumer adoption of other utility-managed DERs. It could also provide an innovative, highly replicable solution as our nation’s fleet transitions from conventional fuels to electricity. SEPA’s forthcoming report, Utilities and Electric Vehicles: The case for managed charging, will cover the current state of the managed charging industry and the opportunity for proactive utility involvement. For more information on the report and SEPA’s Electric Vehicle Working Group, email firstname.lastname@example.org. Erika Myers is SEPA’s Director of Research. She can be reached at email@example.com. Share Share on TwitterShare on FacebookShare on LinkedIn About the Author Erika Myers Director, Research Erika Myers joined SEPA in July 2015. In her role as Director, Erika manages the research content for the organization, oversees research collaborations with key partners, and generates materials related to distributed energy resource technologies. She specializes in renewable energy and plug-in electric vehicle infrastructure and staffs SEPA’s Plug-In Electric Vehicle Working Group. Prior to joining SEPA, Erika spent nearly four years as a consultant with ICF International and five years with the South Carolina Energy Office with a focus on renewable energy and alternative transportation fuel policy and regulatory planning and development. Erika has a bachelor’s degree in biology from Clemson University and a master’s degree in earth and environmental resources from the University of South Carolina.