By Brad Williams and Leo Carrillo, Oracle Utilities
The growing enthusiasm for electric vehicles (EVs) from automakers, consumers, and regional policy makers bodes well for EV adoption in the coming years. According to the International Energy Agency, EV sales had a “record-breaking year despite the pandemic.” The agency estimates that “electric car sales worldwide climbed to over 3 million,” representing 40% growth over 2019.
EV adoption growth shows no signs of slowing. Automakers, such as Volvo and GM, have announced significant moves to sell only EVs by 2030 and 2035, respectively. The Edison Electric Institute, the trade group for U.S. investor-owned utilities, projects that 18 million EVs will travel American roads by 2030. U.S. federal and state governments are expected to bolster demand with their own fleet mandates. The current U.S. government administration, for example, plans to buy large numbers of EVs for its federal fleet. In addition, the U.S. Department of Energy has established initiatives to invest in battery technology and build out 500,000 electric vehicle charging stations.
EVs Will Benefit Utilities
The growing EV adoption wave is great news for utilities, which have been eagerly awaiting EV popularity to offset the lackluster demand growth of the past decade. In addition, EV adoption may also present capital and technology investment opportunities to manage EV integration and facilitate their participation in grid services as a flexibility resource.
Indeed, there are already utilities that are using disaggregation to identify EV owners who are charging at home, which is key to the complex task of managing the grid and expanding charging access beyond the garage. Recently, the “Electric Highway Coalition” — Duke Energy, American Electric Power, Dominion Energy, Entergy, Southern Company, and Tennessee Valley Authority — announced a joint plan to provide a network of fast-charging stations along highways across the US Southeast and swaths of the Midwest, Florida, and Texas.
Acute supply/demand imbalances from extreme weather events or renewable energy variability are fostering even more interest in Vehicle-to-Grid (V2G) programs whereby EV owners or a third-party aggregator can provide grid services by modulating charging rates across large numbers of charging stations or by treating EVs as dispatchable battery energy storage resources for the grid.
Interest in EVs and their potential as an energy storage source has gained so much speed that the Federal Energy Regulatory Commission (FERC) has opened a proceeding on the subject. The goal is to examine how to have distributed energy resources (DERs), including EVs, aggregated in a manageable fashion so grid operators can account for how and when they deliver power back to the energy market.
The technology that will make EVs a dynamic force in energy balancing exists. The next step is reaching critical mass in data collection and analytics to inform decision-making and designs for dispatching such power resources.
Are Utilities Ready?
Hardening the grid for EVs is easier said than done in a time of pronounced regulatory pressure to keep rates as low as possible during and immediately following the COVID pandemic. The traditional regulatory paradigm in the U.S. relies on the notion that only “used and useful” assets should be eligible for cost recovery, and as such, utilities are inherently cautious about making investments against uncertain demand projections — even when the future is knocking.
But predictions are a tricky business, and overly cautious projections can result in acute infrastructure capacity constraints or worse yet, equipment overloads, damage, or failures. With the grid changing rapidly in previously unforeseen ways, the public interest would be well served by forward-looking regulatory support for the planning process and proactive technology and capital investments. Such support might take the form of a “fast track” rate case true-up mechanism and specific regulatory incentives in service territories where distributed energy resources (DERs) or EV penetration levels are changing quickly.
A New Type of Energy Consumer Providing a New Type of Grid Service
While utilities work through the regulatory issues, a new consumer class is emerging — EV owners. Unlike most electric utility consumers, EV owners are naturally attuned to their energy needs, behaviors, and costs driven in part by “range anxiety” from having to plan recharging stops before undertaking longer trips. Rather than being dissuaded by “range anxiety,” EV drivers tend to embrace the challenge in a manner reminiscent of gamification.
Whether motivated by sustainability desires, cost savings or even prestige, EV owners are more likely to embrace analytics apps that demonstrate the ongoing cost savings and carbon reduction they achieve with every charge. As long as they have smart charging technology in place, EV owners are also more likely to embrace customer programs that offer cost savings for off-peak charging given that the majority of EV owners charge at home and have more flexibility as to when charging actually occurs.
Customer programs need not be only for EV owners who charge at home. Since Level 2 and 3 chargers are often equipped with smart inverters that can control voltage as well as rate of charge, even EV users on the go can contribute to grid flexibility by granting permission to an aggregator or power authority to throttle charging rates or cycles once a minimum charging threshold is achieved.
Whether it comes from residential or commercial charging sites, this new form of grid flexibility could become particularly important for grid stability if chargers can be responsive to both frequency and voltage violations, thereby providing synthetic inertia needed to hold the grid together during contingencies. Utility engineers understand that EVs are a source of connected stored energy that could be leveraged with smart charging and ancillary services programs enabling EVs that are plugged in to automatically respond grid events.
Even if V2G programs or manufacturers do not allow EVs to discharge their batteries back into the grid, charging could still be deferred, reduced, or rescheduled as a grid response. Fast Charging Stations already default to limit demand and battery state of charge when charging stations are fully occupied, they could easily do the same during grid congestion as well as reroute vehicles to stations with available capacity during certain peak demand events.
AI and Grid Data Will Drive EV Optimization Forward
In jurisdictions where behind-the-meter installations of DER or EV chargers are not mandatorily disclosed to the distribution utility, utilities should be encouraged to invest in analytics to ascertain where DERs and EVs exist on their distribution network and explore smart charging programs and ADMS/DERMS control systems before they make any infrastructure investments. Once they have a decent read on DER and EV penetration trends and installations, they can more confidently invest in the physical infrastructure such as substations, transformers, sensors and automation to manage variability at the distribution territory or feeder level.
Utilities can also upgrade distribution network management system software and OT infrastructure to optimize power flows to manage load variability while minimizing impacts to power quality and reliability. Using advanced metering infrastructure (AMI) data, modern distribution management systems can apply machine learning to detect and manage EVs at scale. For example, deep learning algorithms can discern EV charging loads from whole-home energy use, providing a utility with digital twin models for an accurate understanding of where and when EVs are charging on its network and how much the EVs are impacting demand at any time.
But knowing is just half the battle.
Armed with robust data and AI-informed analytics, utilities can pinpoint where to invest in grid reinforcement and justify those expenditures in the rate base because they will be made prudently and cost-effectively. And they can use this data to engage homeowners to charge more responsibly and affordably during off-peak times and potentially provide voltage support all the time. Following a year with a record hot summer and unexpected winter in certain areas, investments in analytics and other situational awareness technologies should easily meet the “used and useful” standard.
About the Authors
Bradley Williams is vice president of Oracle Utilities product management, and is responsible for outage management, distribution management, mobile workforce management, work and asset management, and load analysis utility applications and smart grid strategy. Williams has more than 24 years of utility technology innovation experience. Prior to joining Oracle, he was a research director for Gartner’s Energy and Utilities Industry Advisory Services, focusing on utility applications of GIS, SCADA/EMS/DMS, outage and work management, and transmission and distribution (T&D) asset management research. Prior to that, he directed PacifiCorp’s T&D asset management and was responsible for long-term asset strategies and business technology that developed and implemented comprehensive IT investment programs. As director of T&D infrastructure planning, he was responsible for PacifiCorp’s subtransmission planning, telecommunications, and operations technology development groups. Williams also worked at Southern California Edison for 10 years, where he was involved in transmission system planning, distribution automation, and reliability programs.
Leo Carrillo is a senior manager for global product marketing and strategy in Oracle’s energy and utilities global business unit. He joined Oracle in 2019 after many years in the energy and utilities industry with companies like Siemens, PG&E and S&P Global.