Invest in workplace charging infrastructure and provide more flexible electric service and rate options for workplace service providers.

Charging providers might qualify for “network” rates that apply across multiple workplaces that are within the same network to level the overall demand for electricity across the workplace, thereby reducing customer costs. Utilities could also offer separate electric service planning options for building owners and parking lots that could allow separate rate treatments for charging and potentially avoid the need for trenching from existing service, if the parking area is near utility infrastructure (like distribution poles).

Offer incentives for workplaces to install charging equipment.

Examples could include rebates that help lower the costs of installation. State or local government leaders could also offer economic incentives such as tax credits to discourage site hosts from making employees pay excessively for charging at work. In addition, state policy makers could consider offering utilities greenhouse gas allowances under the state’s cap-and-trade program for investments in electric vehicle infrastructure that shift workplace vehicle fuel usage from petroleum to electricity.

Develop new rules to encourage workplace charging.

The South Coast Air Quality Management District amended a rule (Rideshare Rule 2202) that provides compliance incentives for employers to encourage electric vehicle charging, similar to existing carpooling incentives they offer to businesses.

Offer economic incentives or reduce costs for service providers to encourage workplace site hosts to hire them for "full service" charging.

These incentives could address costs from installation to management and could include faster permitting or reduced taxes for service providers engaged in this work.

Reform the green building code to require developers to install not only the conduit but also the charging equipment in new workplace buildings.

The California Green Building Standards Code (CALGreen Code) represents the first statewide “green” building code in the country and already requires Level 2-type infrastructure in certain new commercial buildings. It could also require that any reconstruction of parking lots must include charging infrastructure.

Educate site owners on the potential economic value of low carbon fuel standard credits.

The credits come from a state program that created a performance-based market and mandate for transportation fuels that have reduced carbon intensity, such as electricity. The effort could potentially involve third parties to help aggregate and monetize the credits for users, including public agencies like school districts that may own an electric vehicle bus or delivery truck. Industry leaders and state policy makers could also educate charging station operators about how to manage usage to avoid high demand charges. They could also educate operators on the value of low carbon fuel standard credit options to partially offset high demand charge costs and reduce the cost of electricity as a fuel overall. These credits may currently be widely under-utilized by site hosts.

Compile and promote best practices on workplace charging for potential site hosts.

Policy makers, industry leaders, academics, and nonprofits could accumulate, analyze, and share existing data on workplace charging to inform these practices, including for pricing.

Reform utility rates that discourage installation.

Site hosts at workplaces typically face risks from demand charges and other escalating rates. To offset these risks, utilities could consider allowing site owners to receive some additional revenue from charging infrastructure from vehicle grid integration services.

Assist the private sector, including utilities, in identifying and lowering infrastructure installation costs in critical multi-unit dwellings and areas.

Private installers may spend as much as $11,000 to do
site surveys, interconnection applications, engineering plans, and basic communication with property owners. The state could lower these costs by determining how to prioritize multi-unit dwellings and regions for investment (including by utilities, at least for “make-readies”) and then facilitating education and outreach to property owners. The state could also help offset the cost of acquiring data and information from these buildings, as
well as explore other ways to reduce costs. As one possible threshold, the state could focus on buildings with tenant density of at least 40 units, while generally focusing on larger buildings with the greatest potential impact.

Provide consistent treatment of charger installations to increase predictability and lower the costs of installation.

For example, the interconnection process and fees for this equipment should be as consistent and predictable as possible, across both investor-owned and municipal utilities, in order to encourage investment in multi-unit dwelling charging installations. Utilities could also offer separate electric service planning options for building owners to facilitate separate rate treatments for charging.

Encourage high-concentration building owners like real estate investment trusts (REITs) to install charging.

Such an effort may require reform to existing regulations or development of other incentives, such as tax credits for participating REITs.

Encourage more curbside charging for multi-unit dwelling residents who lack dedicated on-site, off-street parking.

State agencies, in cooperation with local governments, may need to coordinate their permitting and planning processes to enable this deployment. As an example, cities like Burbank and Los Angeles have installed a significant amount of curbside charging (Los Angeles has 32 curbside street light chargers, two wood power pole curbside chargers, and one curbside DC Fast Charger), while Berkeley and San Francisco have not yet installed significant amounts.

Improve upfront data access for charging service providers, with building owner consent, to lower installation “soft costs.”

Service providers and other third-party installers need to access data regarding the building service panel and current energy use in order to know what kind of equipment to install. They need to know the size of the existing service panel (which can range from 200 to 1200 amps), current usage and peak demand, and how much capacity is available on site for the chargers.

Encourage integration of energy storage with charging infrastructure if it would entail additional offsetting revenues and savings from multi-unit dwelling installations.

Utilities often see energy storage as a “new load” that requires them to cover additional costs. Electricity demand from these integrated solutions should instead equal the greater of the two loads, between the vehicle charging and charging the storage asset, and not the sum of the two.

Expand Rules 15 and 16 exceptions for energy storage interconnection to multi-family dwellings.

Rules 15 and 16 cover the process and cost allocations for distribution grid upgrades required when a facility significantly increases its on-site electricity demand. Rather than allow electric vehicle charging infrastructure to trigger this additional process and cost, the California Public Utilities Commission decided in D.11-07-029 and D.13-06-014 to treat electric vehicle-related distribution costs in excess of the Rules 15 and 16 allowances as “common facility” costs not requiring compliance with the rules. Expanding this exception further to energy storage equipment associated with electric vehicle infrastructure could help expedite the interconnection of these assets and therefore decrease the costs of installation, leading to savings through improved on-site load management for the charging facility owner.

Strengthen the green building code to encourage new charging infrastructure when multi-unit dwellings undergo retrofits.

The agency could also develop new regulations or a model ordinance for cities to require such infrastructure through their local codes.

Encourage the establishment of more fast-charging “plazas” in urban areas for multi-unit dwellers.

These residents could then fast-charge a vehicle battery from time-to-time at public sites if they lack access to dedicated on-site charging.

Examine and consider authorizing multiple ownership arrangements to ensure deployment, via a number of business model/ownership options.

Utility-owned (at least “make-readies”) and operated DC fast chargers. This investment could socialize some or all of the costs that are not covered by direct revenues or be partially owned through the “make ready” model.

Automaker-owned DC fast chargers (like Tesla) or collaboration between automaker and electric vehicle service provider. This arrangement would be paid for by a subscription and could be bundled with the purchase price of the automobile. An example would be EVgo’s “no charge to charge” program with new Nissan LEAF customers receiving two years of complimentary charging, assuming this model is scalable.

Public-private partnership. The state could provide more grants for corridors with fast-charging and provide “plazas” for this infrastructure. The state would have to provide detailed specifications, such as the location, number of chargers, and capacity needed. It would have to future-proof the technology to ensure the highest-level charging rate is possible, such as having the utility cover the “basic” fast charge costs and then have the automaker or service provider pay for extra functionality for “premium” service. The state would also need to determine the needs for restrooms and other amenities and assess the scalability potential to maximize the return on its investment. This solution could potentially involve the utilities, because the 350 kW DC fast chargers that automakers want for super-fast charging could trigger the need for demand charge reform or mitigation. If the state helps fund the charging infrastructure deployment through bids from private operators, it could require the winning bidder to secure site host approval first in order to be eligible.

Dual-use model (co-location of charging with other economic activities). This model would work like a gas station, where retail or other economic activity can provide the revenue to offset the high costs of charging.

Automaker/dealer. The two entities can partner on providing the infrastructure, with the costs bundled into the purchase price (although this bundling could potentially raise vehicle prices and therefore discourage adoption), as with Tesla’s network of automaker-owned charging stations.

Investigate optimal locations for fast-chargers, from urban spaces to interstate corridors.

One possibility is to locate the infrastructure at existing gas stations, which would need to be wired for the
technology. However, because gas stations are usually privately owned, developers would have to approach them individually, as owners on average have one-to-three stations with average profits of possibly $40,000 per station per year. As a result, these sites may present logistical and financial challenges for installation. Yet given the ongoing decline in gas station businesses, fast-charging plazas may provide them an economic lifeline.

Encourage utilities to design vehicle-grid integration (VGI) rates.

Vehicle-grid integration refers to the ways that electric vehicles can provide grid services, through vehicles with capabilities to manage charging or support two-way interaction with the grid. The rates that can encourage
this integration include programs such as “real-time” or “day-ahead real-time pricing,” “demand response,” and possibly “vehicle-to-grid.” They represent an important tool to encourage drivers to charge during hours when the electricity grid has spare capacity or to alleviate local distribution-level constraints, rather than exacerbating the system-wide peak demand (particularly in jurisdictions with supply constraints to meet peak demand). Notably, a vehicle-grid integration rate could apply to uses beyond electric vehicle charging, such as appliances that can moderate their usage in a manner similar to vehicle charging.

Adopt incentives for investor-owned utilities to improve the overall utility load factor.

If regulators encouraged utilities to utilize their assets better through performance-based ratemaking and not leave as many idle over time simply to meet peak demand, the utilities could adopt their own incentive programs to encourage optimal charging at all sites in their service territory, potentially without the need for charging-specific rates. Ratepayers could potentially benefit through reduced costs. Utilities could also then take advantage of increasing capacity from distributed and other renewable energy resources. The state already has technology and energy storage policies to implement these approaches. For example, new technology on the market can control charging at a site to flatten the load or reduce overall charging loads to avoid unplanned demand charge events. Similarly, site owners are using energy storage to reduce peak charging loads to avoid either time of use rates or demand charges.

Work together to fill knowledge gaps regarding the best rate design and investment and charging needs for the grid and ratepayers, through demonstration rate programs.

Regulators will need extensive data to help design the most optimal rates for charging, based on existing experience. Utilities could determine how their existing charging infrastructure investments have benefited drivers, the environment, and the ratepayers who have supported programs that subsidize electric vehicles. They could collect and share data on the benefits or disadvantages of scenarios, such as more workplace versus home charging or workplace versus public charging elsewhere, particularly in terms of furthering state goals related to electrifying transportation.

Allow demonstration or pilot rates for investor-owned utilities to gather data on what rates might best encourage optimal infrastructure deployment.

The Commission could also encourage data collection on utilization, maintenance and reliability of the charging
station, and different models of utility investment (such as utility-owned versus make-ready). Municipal utilities could follow suit. These pilot rates could involve rigorous
experimental designs and follow-up evaluation. SB 350 could provide a statutory basis to give utilities direction in designing them. Analysts would then need to test the results thoroughly, and the data from these pilots could be used to inform new commercial rates statewide for investor-owned utilities.

Assist load-serving entities in commercializing vehicle-grid integration technologies to take advantage of new vehicle-grid integration rates.

These on-board car and charger technologies and software can improve response to dynamic rates and help implement smart charging. As the charging software technology within electric vehicles improves and becomes more sophisticated, policy makers could potentially save costs by avoiding duplication of that intelligence in the chargers or other “smart” grid technologies at the site. As a possible step, industry leaders and policy makers at the Commission could consider having vehicles’ on-board diagnostics (which monitor battery performance and charging in electric vehicles) qualified as “revenue grade” after testing and certification for accuracy. This qualification would enable customers and owners to be eligible for the performance-based incentives from vehicle-grid integration rates. Similarly for smart chargers, revenue-grade metrology is needed to support the smart charger concept as well.

Ensure that workplace charging encourages optimal charging patterns to match grid needs through improved rate design.

This design could have outcomes such as more employees charging at home at night rather than during the day when the grid may be more constrained. Or it could involve more daytime charging when surplus solar energy is available. In addition, workplace rates for Level 2 charging could encourage more turnover so employees do not park their vehicles all day for a few hours of sufficient charge, in order to allow other employees to take advantage of a single charging site. Workplaces could also install more Level 1 charging for all-day “slow” charging with less strain on the grid.

Ensure that rates are flexible and tailored for different solutions and use cases.

As an example, a fleet of electric vehicles through Lyft or Uber or at public transit agencies might warrant options for rates that are different for private vehicle owners, in order to reflect the different charging needs and resources that fleets can provide compared to single-vehicle owners. With rate options for fleets, the charging station operator would need to be able to communicate optimal pricing with the fleet operators, in order to notify them when to send their electric vehicles for charging to use surplus or inexpensive electricity. While single-vehicle owners may need charging on-demand at any time, a fleet owner of buses, for example, could potentially charge at night for most of its needs.

Consider other incentives beyond rates to influence charging behavior to optimize the grid

The state could consider using low carbon fuel standard (LCFS) credits or greenhouse gas reduction funds under the cap-and-trade program to give commercial customers a rebate when they do not charge during times that exceed the available capacity of the grid, assuming usage times can be verified easily. As discussed above, the effort could potentially involve third parties to help aggregate and monetize the credits for users. Industry leaders and state policy makers could educate charging station operators about how to manage usage to avoid high demand charges. Industry leaders and state policy makers could also educate operators on the value of low carbon fuel standard credit options to partially offset high demand charge costs.

Maintain and strengthen the low carbon fuel standard (LCFS) program to ensure continued credits are available for charging.

The program is subject to regulatory changes, per statutory authority under AB 32 (Nuñez, 2006) and SB 32 (Pavley, 2016). The agency could ensure that the program continues to provide credits for charging and explore additional ways the funds can encourage optimal charging.

Direct utilities to develop new electric vehicle charging rates that institute alternatives for demand charges with proper cost recovery and strong price signals on timing, such as enhanced time-of-use, demand response or vehicle-grid integration rates.

Utilities and policy makers may want to differentiate commercial rates for bulk-charging uses versus single-vehicle charging and for location-specific charging, if such differentiation can bring specific grid benefits, such as relieving strain in specific areas of the distribution grid or encouraging greater fleet participation in bulk charging.

Adopt “conjunctive” or network billing for electric vehicle charging service providers.

Conjunctive billing  in this context would allow the service provider to pay one electricity bill for all its various charging sites, with the utility billing for these various metered sites as if they were together at one physical location. This structure would allow the individual sites to avoid high demand charges, given the overall high usage when combining the sites together. The structure would not eliminate demand charges but would change the cost recovery mechanism for utilities. Because some locations in the network might be in a grid-constrained area that generate a higher cost, while other charging might be in lower-impacted or cost locations, the collective bill would still need to recover costs in aggregate for all the charging operations, possibly requiring customized billing situations.

Educate site hosts and operators on technology solutions to avoid high demand charges.

Some energy storage solutions and facility energy management systems could offset or reduce these demand charges, as could pricing that encourages charging at optimal times. Energy storage, such as on-site batteries, can help owners avoid spikes in demand by drawing down electricity over a longer period of time and at a lower rate. The energy storage assets can also dispatch electricity during the time of fast charge to avoid the spike and associated costs. Energy management systems can proportionally control charging load to ensure a facility never goes over a specified loading condition. This feature allows the facility to control its demand charge exposure and contain unplanned-for costs. Some utilities also offer “concierge service” for fleets and workplaces to educate them about how to manage their bill, as well as the technology options for doing so, and state policy leaders could partner with utilities for more of these services related to electric vehicle charging.

Encourage the inclusion of energy storage assets, particularly for fast-charging sites, in order to reduce the costs and need for capacity upgrades and encourage the use of vehicle-grid integration and battery “second-life” applications.

Fast chargers in particular, specifically the planned ultra-fast combined-charging standard 350 kW (far exceeding the current 50 kW CHAdeMO and SAE Combo public chargers or Tesla 120 kW Superchargers), require significant amounts of power capacity. They may entail steep costs for distribution and service upgrades, depending on the location. The California Energy Commission, through its Electric Program Investment Charge (EPIC) program, could expand and commercialize its funding for research and deployment to assist regulators with determining how to manage on-site demand long term, including through energy storage deployment when the additional revenue or savings would offset the capital costs. Likewise, the California Public Utilities Commission could encourage utilities to leverage the energy storage inherent in electric vehicle batteries through smart charging, “vehicle-to-grid,” and battery second-life programs. These programs could also help lower the costs of meeting the state’s 50 percent renewables portfolio standard and energy storage procurement mandate.

Develop an easily understandable metric like “e-gallon equivalent” (EGE) and post it widely on all charging infrastructure.

Industry leaders could consider integrating this information for the consumer in a smart phone app along with public charging locations, although the information may be difficult to gather due to time-based rates and different on-board charger speeds in various vehicle models. State policy makers could also mandate transparent pricing at all charging locations. Policy makers could implement this goal through the California Department of Food and Agriculture’s Division of Measurement Standards (DMS), which could propose amendments to the National Institute of Standards and Technology (NIST) Handbook 44 (which ensures “uniformity of weights and measures” for the country).

Educate consumers and dealers on attractive rate options.

Utilities are currently limited in knowing whom to educate because they lack access to information on where the electric vehicles are owned. As a result, the state and utilities could develop creative opt-ins, such as through Southern California Edison and Pacific Gas & Electric’s relationship with electric vehicle dealers to educate new buyers about rates, the Clean Vehicle Rebate Project that generates a list of new electric vehicle buyers/leases, and proposals to limit eligibility for charger rebates and incentives to customers who ‘opt in’ to time-of-use rates. Ultimately, dealers are the likely key point of contact with consumers and could be encouraged to report and communicate with utilities on purchases and rate options. Utilities could also require customers to sign up for optimal rates in order to qualify for rebates and other incentives.