This is the last Dispatch from the Grid Edge for 2020, as GTM Squared takes its holiday break. We will be returning in January with a look forward at the key trends that will shape the grid edge in 2021.
Electric vehicle charging will play a major role in how U.S. utilities operate their power grids — particularly in the states that are pushing the hardest to electrify their transportation sectors.
The Edison Electrical Institute utility trade group projects that more than 18 million EVs will be on U.S. roads by 2030 and will require 9.6 million public charging ports to support them. By 2025, U.S. installed EV charging capacity will reach 31 gigawatts, a load that “could wreak havoc on the electrical grid” if left unmanaged, according to an October report from Wood Mackenzie.
As the two states with the most ambitious EV goals, California and New York will be the first to face the pressure to manage this growing load. California has set a target of 5 million zero-emission vehicles by 2030 and 250,000 charging ports in service by 2025, while New York’s goals include 2 million EVs by 2030 and more than 50,000 charging stations by mid-decade.
This will take a lot of public and private investment. The California Energy Commission has directed roughly $1.2 billion toward EV adoption, from incentives to support for charging infrastructure. California’s three investor-owned utilities are spending more than $1 billion on charging infrastructure and incentives. New York regulators this year dedicated $750 million to EV infrastructure build-out, all but $49 million from its investor-owned utilities.
Utilities may be looking forward to massive revenue growth from selling electricity to EVs and the rate base to come from the capital investments to support their charging. But they’re also under pressure to ensure their approach to integrating them into the grid doesn’t limit the rapid growth of EVs on the road — or end up burdening ratepayers and undermining the case for electrification with excessive costs.
That’s the balance the California Public Utilities Commission is trying to strike with last month’s Vehicle-Grid Integration (VGI) proposed decision. It’s meant to comply with 2019 state law SB 676’s call to maximize feasible and cost-effective EV-grid integration by 2030; variables covered by the proposal range from considerations of grid upgrade costs and electricity supply-demand imbalances to using EVs to absorb renewable power and provide backup power during wildfires and power outages.
“The thing about VGI is that it’s really broad,” said Amanda Myers, senior policy analyst with nonpartisan energy policy firm Energy Innovation. “It’s everything from managed charging and demand response to [vehicle-to-grid] and bidirectional charging.” But underscoring it all is the “need to accelerate the EV adoption and charging build-out.”
At the same time, “if we’re going to have this huge load going in, we have to be really smart about how we’re using it,” she said. California and New York have mandated zero-carbon energy before midcentury. Multiple studies, including recent ones from the Department of Energy’s National Renewable Energy Laboratory and Pacific Northwest National Laboratory, show that EV charging could end up burdening and disrupting the grid or serve as a major resource for absorbing rising levels of renewable energy, depending on how they’re managed.
Eric Seilo, Southern California Edison’s senior manager of e-mobility strategy and new program development, agreed that “VGI is a tool to help us get greater EV adoption” by increasing the value and decreasing the costs of supplying the level of charging the state’s goals entail. But the complexities of how to achieve that are massive. A June report from the CPUC’s Vehicle-Grid Integration Working Group identified thousands of use cases across different sectors and applications, he noted.
“When all of those are combined together, you get a magnitude of different solutions that we have to test and understand." But, Seilo added, “we don’t yet have an understanding of how the market is going to react to those and what the net value will be in terms of deployment.”
From simple to complex: The 80-20 rule for EV charging
The first steps utilities are taking to manage EV charging include requiring smart, internet-connected chargers for homes and businesses benefiting from charging incentives or “make-ready” build-outs of supporting grid infrastructure. Those enable time-of-use rates or direct controls to reduce charging that could overload local grids or systemwide demand peak rates.
All of California’s investor-owned utilities, and many around the country, are integrating time-of-use rates into their EV charging programs, Myers said. That’s certainly true of Southern California Edison’s EV charging program, the country’s biggest.
SCE is spending nearly $450 million to install nearly 40,000 Level 2 chargers at multifamily housing, workplaces, shopping centers and other locations. Another $356 million is going to EV charging for buses, trucks and other medium- and heavy-duty vehicles.
Like many utilities, SCE holds to the “80-20” rule for EV charging, Seilo said, with about 80 percent of EV charging expected to be simple, at-home Level 1 or 2 charging. These chargers must be managed to avoid overloading local grid equipment and to avoid drawing power at times of peak grid demand.
But the tools to ensure this must be simple to manage, like time-of-use rates to encourage charging at off-peak hours, or “set-it-and-forget-it applications” to avoid too many chargers turning on all at once and stressing local transformers, he said. “The other 20 percent, where you’ve got workplace or public charging, you can have more sophisticated communications, or charging based on the time of day,” he said.
Scott Bochenek, director of Northeastern utility Avangrid’s smart grid innovation programs, agreed that the 80-20 rule largely holds for the two Avangrid utilities with the most pressing EV charging goals, New York State Electric and Gas and Rochester Gas & Electric. The New York Public Service Commission has asked all investor-owned utilities to submit mass-market managed charging plans for this portion of their EV load.
The remaining 20 percent of charging is more complicated, he said. NYSEG and RG&E’s are planning roughly 13,000 Level 2 and 400 DC fast chargers as part of New York’s “make-ready” program, with a focus on low-income and disadvantaged communities and medium- and heavy-duty EVs.
Avangrid hired charging software provider EV Connect to provide data and analysis for different use cases for these heavier charging loads, he said. “The key is to understand the impacts on the peak load contribution from the various use cases,” such as apartment and workplace parking lots, retail and downtown garages, or “corridor” versus “destination” fast-charging, he said.
EV Connect has collected lots of data from the thousands of charging systems in the networks it’s been monitoring over the past decade, said Ram Ambatipudi, co-founder and VP of business development and utility engagement. That can help indicate where EV charger concentration can become “substantial enough to start doing active control of the load,” and “what impacts demand-response programs have on the sites that host these charging stations,” as well as on the EV drivers who need their batteries charged within a certain time.
Shedding and shifting EV load: A moving target for grid flexibility
Southern California Edison has required its Level 2 charging customers to enroll in a demand response pilot program since 2016, making it a valuable source of data. So far, EV Connect has seen a relatively smooth-running process for the hundreds of charging ports it manages at workplaces and multi-unit dwellings in SCE territory, Ambatipudi said.
The process includes day-ahead notifications of the need for reduced power consumption, and a day-of notice to throttle capacity by half for a specified number of hours. “We send a notification out to the site host that this is going to happen. We’ve generally seen very little incidence of the site hosts opting out of the event,” he said. “We’ve also not seen many complaints from drivers, in terms of the event impacting their need to get a charge.”
Even so, SCE’s broader EV charging demand-response plans haven’t quite hit all their targets, as a recent report filed with the CPUC indicates. The utility was able to get reductions of between 15 and 23 percent from events called between 4 p.m. and 9 p.m., helping to reduce loads when California’s grid is under the most stress, the report noted.
But its goal of actually increasing EV charging during midday hours when California has excess solar power to absorb — an imperative of the VGI program’s goal of enlisting EVs as renewable power integration — weren’t nearly as successful. That’s primarily because many EVs were already fully charged by then, and because time-of-use prices that rose at noon discouraged extra charging past then, the report stated.
The CPUC is proposing to require utilities to extend EV demand-response programs through 2027 and to create programs to allow third-party EV aggregators to participate by the end of next year. California’s rolling blackouts this August highlighted the role that third-party aggregators can play in meeting the state’s solar-influenced grid imbalances, with companies like Enel X and Leap enlisting megawatts' worth of flexible EV charging.
Enel X has joined Honda, EVBox, Greenlots, Siemens and a set of environmental advocates and industry groups in asking the CPUC to set a more concrete goal for enlisting 200 megawatts of EV charging demand response over the next six years. That may be a relatively small target, given that Wood Mackenzie is forecasting gigawatts' worth of EV chargers will be installed over the next five years.
“By our estimation, even a small percentage of the cars we expect on the road over the next five years could be a meaningful amount of capacity, in the 1,000-megawatt range potentially,” said Ed Burgess, senior policy director of the Vehicle-Grid Integration Council, the group that produced the June VGI report. “Our goal is to unlock EVs as a strategic grid resource” and to provide “new revenue streams [and] new sources of customer value to drive EV adoption.”
Beyond demand-response programs and time-of-use rates, EV industry groups are also eager to find ways to more closely link the price of charging electricity to real-time wholesale energy prices, Burgess noted. San Diego Gas & Electric’s Power Your Drive program includes a pricing plan that changes hourly to reflect real-time grid conditions, and Pacific Gas & Electric is proposing a similar dynamic rate “that would afford more exposure to wholesale market signals,” he said.
Demand charges, grid upgrade costs and unblocking EV charging bottlenecks
Demand response, time-of-use rates and real-time pricing programs are aimed at addressing California’s systemwide supply-demand conditions. But they don’t address another key cost for expanding EV adoption: the limits of local grid infrastructure to supply pockets of high-intensity EV charging.
Even sites that have the capacity to supply power for concentrated EV charging may find the cost of doing so drastically boosted by demand charges, the portion of a large electricity customer’s utility bill based on their peak draw from the grid.
Back in 2017, Southern California Edison issued a five-year demand charge “holiday” as part of its heavy- and medium-duty EV charging infrastructure program. That was primarily in response “to the transit agencies saying, 'The demand charges are killing our interest in converting,'” Seilo said.
But “once you get above a certain load factor, you actually want demand charges,” he said, since those charges broadly correspond to incentivizing customers to reduce maximum grid loads. That’s why SCE’s program is structured to slowly reintroduce demand charges after five years as a “glide path for fleets to start electrifying.”
Major grid infrastructure improvements will be needed as the demand for EV charging at apartment buildings and urban workplaces rises, and as bus and truck fleets convert to electric power. That’s why so much of “make-ready” investments from U.S. utilities are focused on these bottlenecks in grid capacity.
The CPUC’s VGI proposed decision puts a lot of emphasis on this issue, as well as on ways to keep costs in check while avoiding slowdowns in capacity growth. One key pathway could be active load management, a catch-all term for technology and approaches to modulate charging rates to reduce total grid impacts.
PG&E’s $130 million program to support 7,500 Level 2 chargers, launched in 2018, has used active load management to reduce costs at some host sites, by setting up multi-charging sites in ways that reduce total grid draw in the event that all the chargers are being used simultaneously. Halving the full power of chargers in those conditions does double recharge times, but that’s not a problem for full overnight charging — and it also allowed tens to hundreds of thousands of dollars of project savings at each site, PG&E reported.
The CPUC plans to ask all the state’s investor-owned utilities to identify similar opportunities for managed charging at sites where it will cost less to boost electrical capacity and to make this approach retroactive to SCE’s ongoing make-ready efforts. “If there are solutions that might be easier or more cost-effective at the site level, we should be exploring those,” Seilo said.
Avangrid’s Bochenek agreed that New York utilities are “interested in exploring opportunities for alternatives” on the managed charging front. Public charging spots are highly unlikely to see every single charger in use simultaneously, and its partnership with EV Connect could provide real-world data to indicate “what the opportunities are to be flexible, and how disruptive or not some of that flexibility will be.”
Mitigating site-specific loads with batteries is another option, particularly for fast-charging stations where EV operators are less likely to want to delay how long it takes to recharge. Electrify America, the nationwide EV charging network being rolled out via $2 billion in Volkswagen Dieselgate settlement funds, plans to co-locate energy storage at about 120 of its sites by the end of next year, Rob Barrosa, the company’s senior sales and marketing director, said in an October interview.
Burgess of the VGI Council noted that the EV industry parties are eager to find ways to share the cost savings of these managed-charging regimes with charging hosts. “You could install chargers at a lower cost if you get the right rebate — but it also means that the make-ready costs in those...plans could stretch a lot further.”
At the same time, utilities are loath to rely on promises from EV charging sites to determine their future grid planning, Seilo said. After all, “customers can add additional load, and they don’t even have to notify us.”
Even so, “if you have those providers that can manage to some probability those large load pockets in our territory, and some load shift that we can pay for in compensation when they’re called upon, or when things are static, I think that that is how you get to scale.”
The CPUC’s proposed decision would authorize up to $35 million in pilot projects to test solutions to strategies that are “technically feasible but not yet commercially available,” Energy Innovations’ Myers noted. Just what types of innovations could be tested under those pilots have yet to be determined.