The following is a contributed article by David Farnsworth, a principal at the Regulatory Assistance Project.
The meeting had gone on for nearly three hours — a very useful discussion about rate design and electrification. Near the end, our host announced that Mary Nichols, the chairwoman of the California Air Resources Board, was in the building and wanted to stop by and ask us about rate design for EVs. Nichols explained that California had been doing a lot, but that it needed to do more to meet its goals.
Comments came from around the room about the complexity of charging markets, pilot programs and different rate designs. When it came around to me, I reiterated much of what had been said, all legitimate points and good ideas. But later, as I was waiting for the subway, I suspected that I had missed an important opportunity.
I started thinking about what I wish I'd said to Mary Nichols.
EVs as a resource
Nichols is California's chief air regulator, so it's important that she recognize how making transportation work for air quality and climate goals is about more than just building out infrastructure and putting good rate design in place, so that EVs are convenient and cost-effective to buy and drive. It's also about ensuring that EVs are not just an additional source of electric demand, but also a resource in themselves.
When we deploy policies and technologies that shift charging to optimal times, the grid can integrate more renewables — creating a virtuous circle that keeps adding both cleaner end uses and cleaner generation to the power system.
Much electrification load, especially personal EVs and water heating, is flexible and controllable. Unlike the past century, when nearly all electricity needed to be generated and consumed at virtually the same time, today the electricity needed to drive a car or provide many thermal energy services can be generated hours or even days in advance. And because of this, the production of electricity to deliver these services can be managed over the course of the day — in response to conditions on the grid — without any inconvenience to the customer.
This inherent flexibility offers an answer to decades-old utility complaints that renewables are intermittent, and to renewable energy developers' complaints that the grid is too inflexible. That variability and inflexibility can be mitigated where flexible electrification load is recognized as a grid resource that:
- Provides operational flexibility — it offers dual functionality, serving as load while charging and as generation while discharging stored energy back to the grid;
- Has embedded communications and actuation technology — manufacturers have incorporated digital controls into the vehicles and water heaters; and
- Has low capacity utilization, in the case of personal EVs, for example, being idle more than 95% of the time and needing to charge only about 10% of the time.
EV and water heater charging loads are controllable through smart charging, time-of-use rate designs, or both. When combined with strong energy price formation, these mechanisms can provide the financial motivation for flexible consumers to engage.
Charging can take advantage of lower-cost electricity and minimize adverse grid effects and investment costs. It can also be moved to times when variable renewable energy resources are more available, helping integrate these resources and reducing any need to curtail them.
Smart charging and heating can help avoid the need for large new investments in the distribution and transmission systems by shifting these new loads away from peak demand hours to periods of low system utilization.
Optimizing supply and demand
Because of these and other flexibility opportunities, we have moved from a power system once focused on providing adequate supply for anticipated demand, to a system where active supply and active demand can be optimized. We are, in words, moving from a time when we forecasted load and scheduled generation, to a future where to a great extent we can forecast generation and schedule load.
Of course, "optimization," as my Regulatory Assistance Project colleague Carl Linvill reminds me, depends upon one's vantage point.
For a distributed energy resource (DER) owner like a grid-integrated building manager or a DER aggregator, energy optimization takes the external environment — the distribution and bulk power systems — as a given and manages its own investments and resources, like deploying smart inverters.
For a distribution utility, optimization lies in identifying the needs that exist on its system to ensure balance and reliability, and securing resources to meet those needs at least cost.
The distribution utility should articulate system needs transparently through integrated resource planning, distribution system planning and participation in wholesale and other markets. It should also open up its purchasing and procurement processes, structuring them to recognize the capabilities and values of distributed resources like solar PV, EVs and water heaters so those resources can participate and compete.
More broadly, for markets, optimization means that distribution utilities and RTOs should articulate system needs with greater transparency and adopt procurement and trading platforms that recognize the capabilities of all qualified resources, allowing those resources to contribute to system optimization. This in turn can contribute to meeting system needs at least cost or addressing other public interest objectives.
Nichols and her staff probably know all this, but they may think of other ways to take even greater advantage of EVs, heating and other flexibility resources to reduce both emissions and costs.
Will flexible demand-side resources ever be able to participate in power markets in the same way that supply-side resources play? That's really the question before Mary Nichols — and all of us.