Three things you think you know about EVs are wrong July 26, 2018 | By Erika Myers A few weeks ago I had a call with a new research fellow for a well-established energy industry organization, discussing what information and insights about electric vehicles (EVs) might be useful for electric utility regulators. At the end of the conversation, quite unexpectedly, he said, “No one else I’ve been interviewing has said any of this.” Up until that moment, I had never considered my ideas on EVs particularly outside the norm for the electric utility industry, but his comment got me thinking and writing. What follows are three ideas aimed at getting our community to step back and assess whether our current approach to EVs and grid management is at the proper starting point, or if we need to start questioning certain assumptions. My intent is to spur some essential conversations about rates and cost recovery to prevent some of the painful transitions we’ve seen with other distributed energy resources, such as solar. Point: Demand charges are the fairest, easiest way to appropriately allocate distribution infrastructure costs. Counterpoint: While demand charges are a tool to allocate system costs, we can rethink how we distribute those costs across EV infrastructure providers. Demand charges are commonly cited as a barrier to EV infrastructure investments. For example, if a 50-kilowatt (kW) DC fast charger were only used a few times in an entire month, the fast charger operator would still need to pay for the full price of the highest kW demand. The problem here is that the demand charge would be spread across a few customers. This situation has been a roadblock to expanding public charging infrastructure, which many believe is necessary to encourage mass market adoption of EVs. While demand charges are a tool to cover the costs of transformers and distribution infrastructure, utilities could provide different service models that would accommodate their needs, but also encourage EV infrastructure development, such as: Developing demand charges that “step up” as the use of the infrastructure increases — similar to an adjustable rate mortgage. Thus, the demand charge would be lower at first, but then increase based on the load factor at the site. For example, a load factor below 20 percent would be a lower rate to reflect the amount of usage at the site. A load factor above 20 percent would be charged a higher rate, which would likely coincide with a wider customer base to absorb the cost, and thus a higher profit margin for the infrastructure owner. Identifying areas with room on a transformer to accommodate additional load, which, in turn, will reduce impact to the system. In combination with tools to help customers manage onsite load profiles — for example, building control systems or a smart load management program, this approach could balance out the total impact to specific transformers, as well as to the entire grid. Providing customers a storage-as-a-service offering. Such a service would not only reduce the demand charge for the customer, but allow the utility to leverage the storage for grid benefits when the customer is not using it. Financing the bundled cost of the fully installed infrastructure for electric vehicle supply equipment (EVSE), including any dedicated components, through a monthly service fee charged by the utility (i.e., an EVSE services fee). This approach could also include an option to buy the equipment over time, for example, five to seven years. Alternatively, the utility could offer a full EVSE package, including a dedicated transformer, to its customers, with one upfront cost to reduce total utility infrastructure investment. This is similar to other existing utility products. Point: EV time-of-use (TOU) rates are the best and easiest way to reduce on-peak charging and encourage better consumer behavior. Counterpoint: TOU rates are an interim solution at best. While they may be easier to implement, TOU rates are not going to solve the longer-term issues related to EV adoption. They are designed to help steer customers’ charging habits, but they are not effective either in minimizing grid impacts or in promoting good charging habits. In fact, if customers set vehicles to charge as soon as off-peak TOU rates go into effect, the result can be “timer peaks” that impact the distribution system more acutely. Real-time pricing, such as day-ahead, hourly pricing, is a better option to encourage good charging behavior from the beginning. They reflect the true price of energy — similar to the way gas and diesel is sold now — taking into account times of grid stress, and energy surplus or deficit. Consumers are accustomed to these price fluctuations for liquid fuels, and could adjust and plan accordingly for EV charging. If prices were real-time, easy to access, and highly visible — via billboards similar to what we have now at gas stations, or via online portals and apps such as GasBuddy — we could eliminate the issues mentioned above. Why not build on customers’ already-ingrained habits and make our pricing structures more compatible with the actual price of energy? At the end of the day, even if customers pay more to charge their vehicles during certain hours, they are still going to end up spending far less on fuel compared to gasoline and diesel. In fact, San Diego Gas & Electric’s (SDG&E) pilot EV charging program, called Power Your Drive, has successfully demonstrated customer acceptance and buy-in for this very concept. The screenshots below are an example of the app SDG&E developed for its employees to provide day-ahead, hourly pricing information for their workplace chargers. Similarly, consumers can use the program through vendor apps and online resources. Source: San Diego Gas & Electric Power Your Drive is a type of managed charging program, which is a form of demand response. As a business model, managed charging is more sustainable in the long term and provides significantly more grid benefits by allowing utilities to shape and shift load as needed. Further, with the high penetration of solar energy in the SDG&E service territory, Power Your Drive is a way to encourage consumers to maximize the use of renewable energy, while saving money on transportation fuel. In order for TOU rates to be marginally effective they should include: More dynamic elements that reflect seasonal changes in energy consumption and market pricing. Enough of a price differential between off-peak or on-peak rates to influence consumer behavior. A few pennies per kilowatt-hour between pricing tiers is not sufficient. Educational materials and tools to help the customer understand what TOU rates are and the amount of potential savings. Online EV calculators are one such tool, or educational materials customers could receive at EV dealerships. Point: Utilities can build their way out of the EV transition through grid infrastructure investments. Counterpoint: A more effective way to save money for consumers might be to minimize investments in grid infrastructure by leveraging the technology in the vehicles. I’ve had many conversations with utility executives who are concerned about how much longer customers will tolerate rate increases. As customers’ energy options expand, the entire revenue structure for utilities must invariably evolve (see SEPA’s 51st State Initiative materials on the Utility of the Future). A 2017 study SEPA published in conjunction with the Sacramento Municipal Utility District (SMUD) and Black & Veatch looked at SMUD’s projections for EV adoption in its service territory through 2030. Based on those forecasts, SMUD’s costs to upgrade and replace transformers were estimated at $50 – $100 million. The study recommended managed charging as a way to mitigate those infrastructure costs. Even with managed charging, as we electrify our entire transportation fleet, we know that upgrades will be needed for infrastructure, particularly for substations and transformers. Those upgrades can be addressed in one of two ways. Option 1: Utilities can make traditional capital investments in equipment upgrades and replacements. Option 2: Utilities can make new kinds of investments, hand-in-hand with their customers, through non-wires alternatives. Some possibilities here might include energy storage — either in front of or behind the meter — more intelligent grid-edge software, or the use of the on-board vehicle battery itself with vehicle-to-grid technology (see information below about ISO/IEC15118). The non-wires alternatives in Option 2 could help avoid significant grid investments. Such investments could turn into stranded assets if EV owners and their mobile vehicles move out of an area, another vehicle technology emerges, or another charging preference evolves within a community. Business Ideas for a New EV Economy Here are a few business ideas that could solve some of the issues discussed above and fill market gaps as the industry continues to grow. Consider recruiting staff from parallel industries. As we move toward a future of electric transportation, we will need to leverage the expertise of individuals in parallel industries, such as automotive, fleet management, and oil and gas fields. Certainly, as the electric utilities need to provide more energy to meet this new demand, they will need to increase staff on top of filling in gaps from large-scale retirements of some of their most senior team members. For example, oil and gas industry employees are familiar with the basic concepts of the energy market and might be able to inject new ideas into the electricity sector on topics ranging from consumer fueling behavior, to wholesale and retail power marketing, to innovative fuel supply contracts. Given the importance of natural gas in power markets, an understanding of natural gas securities, fuel commodity pricing and forecasting, and trading, options, futures, and forwards could be valuable. Further parallels exist between refinery plant experience, and control and system operations for power plants. Widespread opportunities for career training for a broad range of professionals would provide momentum to transition staff from one sector to the other. Reduce fuel supply risks for fleet operators. Similar to electric utilities, fuel operators do not like risk. Rather than buy a product on the spot market, they will often pay more for a long-term contract for fuel supply (akin to power purchase agreements most of us in the utility industry are familiar with) because it shields them from price spikes and uncertainty. To my knowledge, there isn’t an entity that is the equivalent of a gas or diesel fuel supplier; that is, a vendor that would provide a package offering for a fleet, including a long-term guaranteed price of electricity, EV charging infrastructure, and maintenance of that charging equipment. Contracting for long-term electricity supply already exists within power marketing departments of utilities. Similarly, electric utilities already offer certain large commercial and industrial customers specialized contracts in some cases. Utilities could easily expand these capabilities to include new EV business cases. For example, an electricity (fuel) supply contract could be indexed to a natural gas or renewable energy price plus some base rate over a multi-year contract. Aggregate EV load. Aggregating charging load at the vehicle level and then responding to wholesale power events at the nodal level (EVs are mobile and can move from one node to the next) could be a lower price solution than alternatives, such as non-wires alternatives or energy storage. Aggregated EVs could not only curtail load immediately, but could also absorb excess capacity — also known as reverse demand response. Despite a number of technical and financial (e.g., battery warranty) roadblocks, the ISO/IEC15118 standard could pave the way for greater visibility and access to this kind of vehicle charging in the future. The list below details the EV manufacturers now integrating this standard into their cars. Financial incentives for customers will likely be needed — for example, to get customers to participate and share data, curtail charging, and reduce their driving distance. But as we have seen for other demand response products that include customer incentives, such models still leave room for profit. As the EV industry market evolves, there will be hundreds of challenges along the way. I know that by committing to work on this transition together, we will witness one of the greatest changes in our transportation system since the invention of the automobile. We have a once-in-a-century opportunity to collectively use our knowledge and resources to ensure a better future. SEPA is proud to be one of many organizations addressing these — and many other — clean energy challenges through our conferences, workshops, and working group activities. I welcome your feedback and ideas to share with our community, please email me at firstname.lastname@example.org. Share Share on TwitterShare on FacebookShare on LinkedIn About the Author Erika Myers Principal, Transportation Electrification Erika H. Myers is a Principal of Transportation Electrification for the Smart Electric Power Alliance (SEPA). Erika has 16 years of experience in the clean energy sector and specializes in the nexus between the grid, electric vehicles, and renewable energy. She leads SEPA’s content for transportation electrification and manages SEPA’s Electric Vehicle Working Group. She has authored and co-authored numerous reports, briefs, and articles and regularly speaks at events around the country. Prior to joining SEPA, Erika spent four years as a consultant with ICF International and five years as the Renewable Energy Manager for the South Carolina Energy Office, specializing in 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 with a specialization in clean energy.