Imagine you are preparing dinner for guests arriving at 6 p.m. when you learn that they’ve been delayed. And imagine that, instead of keeping the food hot, you had to throw all of it away and start cooking again for the actual time they come in the door. Wasteful and unacceptable, right? If you are an electric utility providing energy for consumption at a specific time and the demand isn’t there, that’s exactly what you have to do: throw it away.
The obvious difference between these two examples is the ability to store food in one case and the inability to store energy in the other. If guests don’t show up, the cook simply puts the dinner in the fridge for later consumption. But in the power system, if the demand for electricity, or “load,” is not there, the grid manager often has to “curtail” generation—i.e., throw it away. Lawrence Berkeley National Laboratory reports that in 2016 across the country’s seven organized wholesale markets, grid operators, on average, threw away about 2 percent (and in several cases over 4 percent) of electricity from variable renewable energy resources like wind and solar, because the demand for it wasn’t there when the energy was available. As those clean resources become cheaper and cheaper, wasting them probably makes even less economic sense.
How can we avoid wasting this low-cost energy? One good way is through beneficial electrification. Some electrified end uses—like charging electric vehicles and heating water—don’t require electricity from the grid at the moment they are used. Therefore, much of the new load added to the system by these uses is inherently flexible and can serve as energy storage. As a result, the power system can reduce curtailment and serve that flexible load at cleaner and less expensive times of the day. Let’s look at these end uses and consider how they can give grid managers greater flexibility in optimizing their systems.
Electric Vehicles (EVs): Potential to Cut Costs for Everyone
EVs constitute a significant source of flexible load because the batteries that power them can be charged whenever is most beneficial to the grid. This flexibility means that EVs can actually improve the utilization of the transmission and distribution system, shifting loads that would otherwise add to system peaks, which ultimately drive grid investment and increase cost. The need for system upgrades can be minimized if EVs are charged during off-peak periods, either through smart charging, time-of-use pricing, or some combination of both. EV charging flexibility also provides the potential for vehicle-to-grid (V2G) services or two-way charging, which essentially allows for an EV’s battery to serve as a storage device available to discharge power back onto the grid when called upon.
Adding EV load can also contribute to lowering the average cost to serve all customers, not just EV owners. Analysis of EV adoption scenarios in California by Energy and Environmental Economics (E3) found that there can be significant utility system benefits from adding EV charging load to the grid. E3 found that utilities’ cost to serve the load added by substantial EV adoption was less than the amount of revenue they would bring in from customers charging EVs, thereby reducing the cost of providing electricity for all ratepayers.
Utility System Costs and Benefits from EV Charging in California
Water Heating: Load-Shifting and Ancillary Services
Uncontrolled residential water heating usage usually peaks in the morning and evening hours, when consumers start and end their days. The figure below characterizes typical residential hot water heater electricity usage for an upper Midwest state, by hour of the day and month of the year. From a grid management point of view, this demand trend occurs at different times of the day from typical solar production (mid-day) and the most common wind production (overnight). This means that flexible water heater load can be moved off-peak to “charge” water heaters during cheaper and lower-emitting hours.
Water Heater Usage from the Upper Midwest
Source: Steffes Corp.
Electric resistance water heaters (ERWHs) and heat pump water heaters (HPWHs) are examples of this flexibility. Because the water tank of an ERWH can typically store a full day’s supply of hot water, it doesn’t matter when it is charged. Its energy use can be curtailed during peak, daytime hours and that load can be concentrated into low-cost (and low-emission) hours of the day. Heat pump water heaters can also be controlled to provide load-shaping and capacity benefits to the system.
In addition to load shifting, flexible electrification load can help in providing “ancillary services,” another category of tools used by grid managers to ensure power system reliability and meet operational requirements. Smart electronics and improved communications are creating a new category of responsive appliance resources that enable grid managers to control the heating elements of ERWHs in very short increments for various uses.
This flexibility allows a utility or aggregator to provide valuable ancillary services to the grid, such as frequency regulation (a transmission-level service) or voltage support (a distribution-level service), to help ensure that the grid operates efficiently and reliably. Because HPWH compressors are mechanical devices that could suffer unacceptable wear if controlled down to the sub-minute periods required for fast-response services, they are not currently suited to provide fast-response benefits.
Space Heating: Tapping the Smart Thermostat
The electrification of space heating—where technologies have previously relied on fossil fuels—also holds great promise. When connected with smart thermostats, for example, air source heat pumps can help manage system demand by preheating a space during the afternoon hours and running less during the early evening peak. Smart thermostats can enable demand response programs whereby a utility can reduce the electric load of a group of heat pumps by an individually small amount. Taken as a whole, these reductions can provide a measurable peak load reduction benefit to the grid and also reduce air emissions.
Waste Not, Want Not
As we have noted in our publications, for electrification to be considered beneficial, it should meet one or more of the following conditions without adversely affecting the other two:
- Saves consumers money over the long run;
- Enables better grid management; and
- Reduces negative environmental impacts.
The flexibility enabled by electrifying end uses constitutes a new tool and source of value for managing electricity grids. For consumers, smart charging programs featuring time-of-use rates can provide the exact same service but at less expense and often with cleaner electricity. For system operators, flexible loads represent the opportunity to have greater control of the power system by shaping demand, and to optimize system efficiency by enabling greater use of existing resources.
The chart below shows the penetration of wind resources in ISOs around the United States, and also their curtailment between 2008 and 2016.
Wind Curtailment and Penetration Rates by ISO
Source: U.S. Department of Energy
By moving flexible electrification load to times when these resources are being curtailed, grid managers could charge EVs and operate space and water heating heat pumps using the thousands of GWhs currently being wasted. By moving load to times when it can be served by cleaner, cheaper resources and avoid system peaks, grid operators can save money and emissions over time—both for themselves and ultimately for ratepayers.
In short, by fully engaging the flexibility of newly electrified loads on the power system, grid operators can “toss out dinner” a little less often and reduce the waste of valuable energy resources.
This is the second in a series of RAP blogs exploring aspects of beneficial electrification.
Getting the Most Out of Vehicle Electrification, in GTM, If managed well, electric vehicles present a massive opportunity for utilities to invest productive capital into the distribution system.
Bloomberg New Energy Finance projects 40 percent of U.S. new-car sales will be electric in 2030, with EVs becoming cost-competitive without subsidies around 2025. That’s an extra 24 terawatt-hours, or half a percent, of new flexible demand, added to America’s power system annually in just over a decade — a regulatory blink of an eye. Depending on when EVs charge, that translates to 3 to 6 gigawatts of flexible demand-response capacity added each year — roughly half of today’s total demand response capacity in PJM Interconnection.
Electric utilities will play a major role supporting transportation electrification, and as electricity providers, they will benefit from additional sales and infrastructure required to meet new demand. An International Council on Clean Transportation report found a statistically significant link between grid-connected EV infrastructure and vehicle electrification, and a Brattle Group report showed electricity demand from a fully electrified transportation fleet in 2050 dwarfs potential lost sales from distributed solar generation by a factor of five.
So whether or not utilities are allowed to own and rate-base charging infrastructure, massive investment opportunities are coming down the road. But if utility shareholders receive new earnings opportunities through EVs, what value will customers get in return?
Last year, America’s Power Plan published a five-step framework for getting the most out of grid modernization to ensure customers get the value promised from grid modernization investment programs. Electrification is one subset of these efforts, and a similar approach (adding market development as a precursor) can help regulators prepare for immense market changes. Getting the most out of vehicle electrification requires supporting market development, conducting integrated distribution planning, defining goals, setting metrics, defining targets and exploring changes to utility financial incentives.
Step 1a: Supporting market development
Before developing a comprehensive EV evaluation framework, utilities will have to experiment and innovate. In the short term, before EVs ramp up, regulators should support innovative grid-edge applications through pilots and an initial round of EV infrastructure (rate-based or not), laying the groundwork for EVs to become grid resources. In order to turn EVs into reliable demand response and storage resources, these applications need work to be made operational in a reliable way, including through communication protocols, standards and consistent operational practices. New rate designs will also have to be tested and developed.
Public utility commissions haven’t yet developed robust frameworks for assessing the prudence of utility charging infrastructure investments, so initial approval of a closely watched first round of experimental investments can encourage innovation and inform regulation. Commissions may consider allowing utilities to provide incentives to help customers electrify in this early phase, then pare back incentives in the future under a more comprehensive approach as the scale and scope of EV infrastructure grows and the industry becomes more mature. The Rocky Mountain Institute report Pathways for Innovation provides a useful roadmap from experimentation to deployment.
Step 1b: Integrated distribution planning – EV edition
Integrated distribution planning (IDP) determines the hosting capacity and potential benefits of distribution system resources under different utility control scenarios — a prerequisite to optimize distributed energy resource deployment alongside conventional supply-side resources. IDP is heating up, with new proceedings in Maryland, New Hampshire, New York and Minnesota (see the 50 States of Grid Modernization for the complete list), joining early adopter states like Hawaii and California.
Among other valuable results, IDP generates the data utilities need to understand where and when EV charging can provide the greatest benefit of all customers. One key element is location; IDP helps identify uncongested circuits with the smallest incremental cost of adding charging capacity. On congested circuits, EV chargers that would otherwise add to the stress can reduce their systemwide impact if customers receive charging incentives during periods of low demand. In addition, IDP allows utilities to:
- Plan for various rates of EV adoption
- Understand the benefits of smart versus regular chargers
- Plan for different combinations of autonomous vehicles, public EV fleets and individual customers
These efforts should be coordinated with municipal and state transportation agencies that will likely play primary roles in vehicle electrification, including route planning, congestion and clustering of public-facing chargers.
Finally, IDP provides visibility into the economics and viability of EVs as system resources for managing of wind and solar variability. Rather than build new natural-gas peakers, smart chargers capable of responding to system operator control can help manage peaks by delaying charging.
Step 2: Define the goals of a vehicle electrification program
The second step starts by asking what regulators, on behalf of customers, hope to achieve by allowing utility investments in EV deployment, and what role the utility should play. The traditional goals of providing affordable, reliable, safe power aren’t going anywhere, and EVs should help achieve these goals. But other goals, such as facilitating customer charging, improving local air quality, and power-sector decarbonization will also impact EV infrastructure and demand management.
A key EV deployment goal should be increasing service convenience and quality for a growing EV customer base. Serving customer demand for EVs, including disadvantaged communities, means facilitating new smart charger rollouts and demand management systems that help customers charge rapidly, in many locations, as cheaply as possible. Though investment is required, time-varying rates and demand response payments can help enhance the affordability of EVs, improve existing infrastructure efficiency, and enable autonomous EV charging and aggregation as flexible resources.
Local air quality is another common goal of vehicle electrification, which will likely benefit low-income communities that tend to have worse air quality than average. Because the utility plays a significant role in supporting EV deployment, some benefits to local air quality can be attributed to their performance in promoting EV adoption.
EVs not only decarbonize the transportation sector, they also help decarbonize the power sector. Vehicle electrification has great potential to facilitate integrating local and bulk-system renewable energy resources, such as by adding flexibility by shifting demand from one hour of the day to another, or by providing short-term frequency response. Shifting is a key strategy for integrating variable renewables from the Regulatory Assistance Project report Teaching the Duck to Fly. If vehicle manufacturers and customers can agree on rules for discharging, this flexibility potential will nearly double.
Step 3: Metrics of a successful vehicle-electrification program
Metrics should focus on outcomes reflecting policymaker goals. If it is a state goal, electrification itself should be measured and publicly reported by the utility, in terms of energy (kilowatt-hours), customers (vehicles/customer), electric-vehicle miles traveled, and peak-coincident charging. These four metrics help customers understand progress in meeting transportation electrification goals. Regulators can also consider comparing overall spending on charging infrastructure with electrification metrics, giving a sense of grid spending per unit of electrified transportation.
Often, vehicle electrification outcomes are subsets of a greater goal, such as clean energy, affordability or reliability. System metrics for grid modernization or clean energy can subsume vehicle integration metrics. Because new vehicles necessarily increase demand, utility performance in key areas like peak demand management (percent megawatt reduction), efficiency (kilowatt-hours per customer), or carbon emissions (carbon dioxide emissions per megawatt-hour) or other air pollution, must therefore account for “beneficial electrification,” while maintaining high standards for reducing impacts of EV adoption on those outcomes. For example, when New York’s Consolidated Edison recently adopted an outcome-oriented efficiency metric, kilowatt-hour per customer, it normalized for vehicle and appliance electrification by adding in customer load to the target.
Step 4: Create an open process to set targets
Once metrics are selected, reasonable targets can help guide utility planning. A transparent target-setting process should include plenty of time for stakeholder review and comment, and targets should be set far enough into the future to accommodate investment and program timelines. Regulators should consider the unique context of each region or utility and place targets within a range that represents a stretch, but not an unreasonable one.
Pilots can be helpful where the potential for utilities to optimize EV charging via rates or demand response is unknown. For example, a recent BMW-Pacific Gas & Electric pilot program successfully demonstrated that EVs can serve as reliable and flexible grid assets, giving regulators a sense of what is possible.
Target-setting is part art and part science, raising the importance of a transparent and predictable process for calibrating targets based on real-world performance. Laying out the target revision process ahead of time is critical to lowering utility investment risk.
Step 5: Consider linking utility returns to performance
Many different resources explore options for reorienting utility compensation around performance, including Synapse’s Handbook on Utility Performance Incentive Mechanisms, America’s Power Plan’s Cost and Value series (parts one and two), RAP’s report for the Michigan PUC, and Ceres and Peter Kind’s Pathway to a 21st Century Utility. Many of these concepts are in the proving phase in the U.K. and are being implemented in New York and Massachusetts. They’re also being explored in “utility of the future” proceedings in Illinois, Ohio, Minnesota, Oregon and Hawaii.
For EVs in particular, two methods could be helpful — a conditional rate of return on charging infrastructure based on performance (if allowed) and overall performance incentive mechanisms. Utility commissions have found it (and will undoubtedly continue to find it) prudent for utilities to build, own, maintain and operate charging infrastructure, particularly on public property, in low-income areas, and for large businesses and parking structures. In such cases, key metrics outlined above could be linked via basis-point adjustments to utilities’ return on investment on those rate-based assets. Regulators could also set a revenue cap on charging infrastructure, with incentives to achieve electrification targets while spending below budget.
Performance incentives are essentially cash bonuses increasing utility returns if specific targets are met, while penalizing the utility when they fail. For example, a utility could be rewarded for reducing peak demand below the target set by regulators by turning off EV chargers when needed.
Electrification presents a massive opportunity for utilities to invest productive capital into the distribution system. Reorienting utility investment around outcomes can help customers get commensurate value in return.
Michael O’Boyle represents America’s Power Plan.