by Shahid Malik, PRTM
President Barack Obama set a goal of having 1 million electric vehicles (EVs) on U.S. roads within five years. But without electric utilities’ cooperation, the EV movement will go nowhere. Utilities must understand how EVs will affect their business and operating models and what companies must do from an infrastructure standpoint to connect these vehicles to the grid.
The Size of the North American EV Market
The tipping point for EV ownership could come at the end of this decade as the EV payback period approaches that of an internal combustion engine (ICE) vehicle. PRTM estimates that by 2020 battery-powered EVs will have a 4 to 5 percent adoption rate; the rate for plug-in hybrid EVs (PHEVs) will be 5 to 6 percent; and hybrid EVs (HEVs) in total will reach 20 percent (see Figure 1).
Many scenarios exist for U.S. EV penetration, and numerous factors will determine EV commercial viability. For potential EV consumers, driving range, total ownership cost (i.e., purchase, maintenance and refueling) and ease of recharging are most crucial.
Today, some 70 percent of gasoline-fueled vehicles in the U.S. travel fewer than 40 miles a day, with 60 percent traveling fewer than 30 miles. (The typical ICE vehicle has a 300-mile range). Most EV batteries will have a 40- to 80-mile range on a single charge.
Chevrolet in September announced that the new Volt battery will have a 40-mile range depending on driving conditions and ambient temperature. The additional gasoline tank will provide another 300 miles.
Similarly, Nissan said its all-electric offering, the Leaf, has an approximate 80- to 100-mile battery range. Range anxiety should not deter early EV adopters. As battery technology improves, range will play less of a role in purchasing decisions (see Figure 2). Other more traditional factors—price, styling, performance, packages and services—will become more important.
Total Cost of Ownership (TCO)
Automakers should find a ready market for EVs as long as the vehicles are reasonably priced compared to gasoline-fueled vehicles. Demand already is strong for the Leaf. Assuming there is a $7,500 federal tax credit and $5,000 state rebate, the Leaf will cost about $25,000 in California; the Volt will cost about $28,500. Governments cannot afford to subsidize EV ownership forever, however; the market must reduce costs dramatically for these vehicles to be affordable long term.
An EV’s largest cost component is the battery. Technological advances have been dramatic in the battery space, driving down prices per kilowatt-hour in recent years.
PRTM analysis predicts battery costs will continue to fall from about $650 per kilowatt-hour today to about $300 per kilowatt-hour by 2020. Lifetime fuel and maintenance costs for an EV will be substantially lower than those of a gasoline-fueled vehicle.
When it comes to refueling EVs, not everyone agrees it is the natural domain of utilities. Oil companies will not give up their gasoline business without a fight. Gasoline at the pump is not necessarily profitable on its own, but in combination with high-margin convenience stores, repair shops and credit card offerings, it constitutes a compelling value proposition.
Likely there will be electricity resellers—Walmart, McDonald’s Corp., The Kroger Co., etc.— that will subsidize the cost of charging vehicles at their own proprietary charging stations to convince more people to visit their stores. State public utility commissions (PUCs) are addressing this.
The California PUC recently declared that resellers would not be subject to the same regulation as electric utilities. Assuming this ruling survives the appeals process, it will cause disruption and promote competition and innovation in the traditional electric distribution business.
The Impact of EVs on Utilities
Utilities should prepare for EVs in three main areas: technical impact, regulatory challenges and business model changes.
Technical Impact. From a system integrity standpoint, most early EV adopters likely will be in affluent neighborhoods. Without system upgrades, clusters of EVs charging in one neighborhood at night could overload local transformers and circuits. When Level 3 fast charging—less than 30 minutes—becomes prevalent, the risk of damage to the utility infrastructure becomes greater and the need for upgrading equipment more urgent. Such charging likely will be in public places such as malls or parking garages.
In general, utilities excel at planning infrastructure modifications once most of the elements are in place. In this case, considerable uncertainty surrounds the impact and timing of the new demand. EV demand planning must become part of the overall smart grid planning process, particularly because smart grid technology can mitigate the risk of overloading circuits and transformers. Because vehicles roam, smart meter technology also will play a role in enabling EV connectivity inside and outside a utility’s natural service territory.
Smart meter technology also can help EVs sell electricity back to the grid during power shortages. Vehicle-to-grid (V2G) opportunities might increase, but logistical problems exist in enabling electricity resale onto utilities’ networks. And the price spread between what a customer pays for electricity and what he or she could earn selling it back to the grid must be considerable to overcome range anxiety or concerns that constant discharge and recharge could invalidate the battery’s warranty. Some companies will try to aggregate this load to take advantage of independent system operator (ISO) and regional transmission organization (RTO) energy or ancillary services—services performed by electric utilities to support the integrity of the power delivery system—payments, creating potential demand and supply swings on the utility’s grid. As a result, utility companies must be ready to participate in the changing of ISO and RTO rules to accommodate such activities and the extra information technology investment required.
Infrastructure demand planning will be critical for ensuring the electric load is served without disruption. The U.S. electric supply is adequate under any reasonable scenario to meet early penetration estimates. The challenge lies in managing load and maintaining system integrity. Electric Power Research Institute (EPRI) studies show that the total charge associated with a new EV likely will double the electric consumption of that person’s home. The grid’s total capacity, however, is much larger than forecasted demand, and utilities will be able to accommodate this extra load provided it doesn’t all come at peak times.
When thinking about charging stations and related infrastructure, investors and utilities must ask themselves, “How much EV penetration will there be? Where will the vehicles’ owners want to charge? What impact will there be on the grid? What is the return on investment (ROI)?”
Regulatory Challenges. Who will fund the infrastructure investments to pay for the charging stations, utility network upgrades and end-to-end systems integration? Every discussion PRTM has had with utilities has begun, “What will the regulators do, and what will they allow us to earn?”
The answer varies by state. EV policy is fragmented because each state’s PUC has the right to determine which business cases would benefit electric customers most and deserve support through the ratemaking process. Consequently, it is critical utilities engage regulators early and often. Utilities must represent their points of view to their respective PUCs before other market participants have undue influence. Some PUCs (e.g., in California) are formulating an EV framework by working with utilities and other interested parties. Most other PUCs are starting to learn about EVs often in the context of smart grid deployment or carbon emissions. PUCs will be expected to support the numerous charging options required to promote EV growth. From a policy perspective, consumers must be able to charge their vehicles at their convenience and at reasonable prices. Gasoline costs $3; the equivalent for electricity is less than $1 a gallon. Regulators have considerable leeway for allowing price increases to utilities interested in making infrastructure investments.
Utilities will discuss with regulators: Who should own the necessary infrastructure? How will it be paid for? What will be utilities’ additional obligations to customers? What prices will customers pay for recharging? And in deregulated states, how will retail electricity suppliers take advantage of this opportunity? How should utilities share data with other utilities and nonutility vendors such as McDonald’s and Walmart, and how should they address security and privacy issues that will arise?
PUCs can resolve some of these questions. The federal government, however, working with states, must make overarching policy decisions and standards for hardware, software and security. Otherwise, a patchwork of regulations could stunt the EV market’s growth.
Business Model Changes. There are more than 3,000 U.S. electric distribution companies: investor-owned utilities, municipally owned cooperatives and so on. Each utility operates within a defined service territory carefully regulated at the city, state or federal level.
Most states regulate their electric distribution utilities through a PUC that approves utility investments and decides on the appropriate return on capital. As a result of all these policymaking bodies, it is difficult to build economies of scale until winning models emerge.
This helps explain why the largest U.S. utilities are relatively small and numerous compared with their European counterparts. Such fragmentation makes it hard to agree on common standards for new technology such as EVs.
Utilities, therefore, must understand how to evolve their business models to generate the most profitability from the EV value chain while minimizing risk. Regulated utilities earn a rate of return on their assets as authorized by their respective regulatory authorities. The size of the capital base, geographical area and customer base largely determine a utility’s earnings.
The new EV market, however, will change dramatically the traditional auto and oil industry value chain with value shifting from automakers to battery companies and from oil companies to electricity providers. Utilities must decide where they fit along the new value chain.
The biggest opportunities for utilities are charging infrastructure investments. PRTM estimates that the payback on such investments initially will take longer with a lower ROI than utilities are getting on other investments.
Recognizing this, farsighted utility regulators have started to promote the build out of limited infrastructure through incentive-based rulemaking in some service territories. Figure 3 depicts how utilities can target infrastructure investments to meet their operational goals.
Other revenue-making opportunities for utilities include services such as customer billing and software applications for EV owners. These capabilities, however, have not been strengths of utility companies.
PRTM does not favor EVs’ discharging their batteries onto the grid to arbitrage the difference between their off-peak charging cost and the on-peak value of electricity. Significant opportunities exist, however, for utilities to facilitate their operations by controlling the charging of batteries to match their grid requirements. Such ancillary services have value for utilities, as the current model of firing up generation plants to meet load can be partially reversed if the utilities have some control over when and at what rate EVs can charge. Load can be shaped to meet available generation capacity, which provides considerable flexibility to utilities. This ancillary service, commonly known as reg-up or reg-down, has operational value and a price on the daily electricity market, where such services are provided for a fee. Such innovation is a small taste of what will be available for companies as they search for revenue-enhancing opportunities.
Most utilities will not want to change their business models radically this early in EV market development. Instead they will consider how to maintain their flexibility. A good way to learn about the options is to get involved with the growing number of EV coalitions and to talk to potential partners and auto industry insiders.
Getting EV Ready
To prepare for the enormous changes, utilities must address four sets of challenges:
1. Do we have the capacity? Can the system handle it? What times of day will the load be required? What price can we charge? EV market growth represents an electrical engineering challenge for utilities. Assets most at risk are transformers in high-penetration EV markets. Utilities must analyze their customer bases and identify likely points of overload and failure. Such infrastructure must be upgraded and maintained more regularly than transformers in other areas. Upgrading the asset base increases the value of the rate base, and it might be difficult to get PUCs to authorize the additional capital expenditure upfront. Early outreach to regulators is critical. It ensures commissions understand what might be required. The commissions know the public will not stand for repeated transformer-induced outages, especially in wealthy neighborhoods, so a strong business justification should be possible.
EV owners likely will require separate meters or submeters at home to take advantage of special power prices for EVs. Because charging could take up to eight hours, EVs must be able to charge during off-peak hours. Fast charging likely will not be required at home, but market research shows there is demand for it at public charging stations—even at a substantial premium.
Utilities must consider whether they want to own, maintain and service this additional meter and who will own and maintain the EV service equipment on customers’ premises. For Level 2 charging, this includes the service panel, the wiring to the charging location, and the equipment that safely will manage the voltage used to recharge.
Electricity pricing is a contentious issue in every state, and studies are underway to assess EV price elasticity of demand. Regardless, there is a concern that charging EVs during peak demand periods could lead to power shortages.
The obvious but not necessarily acceptable answer is to introduce variable pricing to encourage off-peak charging. California and Michigan have introduced some variant of time-of-use (TOU) pricing as pilots to balance utility and consumer interests. Utilities must perform their own analyses of TOU pricing and present strong business justification to their PUCs to win approval of such rate structures.
2. Assuming no change in the overall business model, what are the product extensions and options available to utilities? Is this a threat or an opportunity? Massive EV adoption will upend automotive and oil companies’ business models. For U.S. utilities, the additional EV load offers a substantial opportunity: Electric vehicles will increase electric consumption and require associated service offerings. But it also poses a threat with the potential to disrupt traditional utilities’ business model, introduce new competitors and strain grid stability.
Electric utility services generally stop at customers’ meters in homes or businesses. The meters may be utility-owned, but everything else traditionally has been the customers’ domain. The introduction of smart meters and home area networks, however, provides an opportunity to extend utilities’ reach into homes and offices. Although it is unlikely utilities will start selling electric appliances to service the EV market, they could have access to the EV support market in a much bigger way by providing downstream energy consumption analysis, software applications that provide charging maps, prices and availabilities, and credit and billing services, etc.
Inevitably, innovative services and products will emerge downstream of the meter. Then utilities must decide whether the attractiveness of this usually deregulated market is worth the effort and risk.
3. How should utilities manage customer expectations and ensure they have a positive experience even though there likely will be a fair amount of disintermediation between utilities and end consumers? Utilities will benefit by studying EV impacts on their systems and by understanding customers’ behavior and profiles. But gleaning this level of insight from customers will require significant outreach. As we have learned from smart meters, in vital industries such as energy it is important to engage customers before introducing new technologies. Customer education and stakeholder coordination are prime areas for utilities to be involved early and often.
4. Assuming that the regulatory construct is favorable, how should utilities organize internally, and how should they plan for and deploy the infrastructure? Utilities must make organizational changes to accommodate this new service offering. A separate organization for EV enablement will become cost-prohibitive, so utilities must build an organization that supplies customers effectively but that interfaces seamlessly with the retail, distribution and customer management services, including IT systems.
Before customers purchase EVs, utilities must focus on service provisioning and enablement. Operationalizing this whole chain of activity, however, can become burdensome. Utilities must integrate these activities into normal operating practices and legacy systems to handle activities such as service enablement and charging station deployment, contract management, billing, maintaining customer databases, enabling roaming and remote connectivity, tracking carbon emission credits and preparing work orders.
A detailed program management and deployment approach will be critical for ensuring provisioning is done consistently, efficiently and in a scalable manner.
Utilities must be ahead in this emerging market opportunity by keeping a customer outreach perspective in mind and by preparing an infrastructure study and deployment plan for implementing the necessary infrastructure in a timely, effective and cost-efficient manner.
Large-scale EV penetration will have broad corporate implications for utilities and how they handle customers. Early adopter satisfaction will be paramount for spurring other consumers to purchase EVs. Because regulators keep a keen eye on customer-satisfaction ratings, utility companies should get EV ready as soon as possible.
Shahid Malik is vice president of PRTM. Reach him at email@example.com.
Past EL&P Issues