Aggregated flexible load of high EV penetrations will be lucrative in demand response markets, but for now smaller EV demand gives utilities management practice.
Herman K. Trabish, Oct. 18, 2019, Utility/Smart Cities Dive
Electric vehicle (EV) charging may eventually offer power systems great load flexibility opportunities, but today’s modest EV penetrations may be more of a challenge than a benefit for utilities.
EV adoption is growing fast, but only in some areas. Too much simultaneous charging in these areas could be a threat to distribution system stability, requiring costly new infrastructure. Utilities are moving to EV-specific time of use (TOU) rates, a type of demand response (DR) with price signals, to get customers to proactively move charging in these areas away from peak demand. But that may not be enough.
“A few level two chargers used at the same time, anytime, can strain a local distribution grid,” Brattle Group Principal and flexible load authority Ryan Hledik told Utility Dive. “In the near term, control of that EV charging demand is an important piece of the distribution system management puzzle.”
Despite the limited adoption that keeps EVs from being a system-wide threat now, utilities need to develop active responses for controlling localized EV charging demand, power system authorities told Utility Dive. Early trials of EV-charging-as-DR have had limited success, they acknowledged, adding that utilities must learn to manage clustered charging to be ready for high EV penetrations.
The demand and the response now
The need for utilities to respond to new demand from EVs, especially from clustered charging, could come sooner than many expect, Brattle’s Hledik said.
Today’s more than 1.27 million EVs on U.S. roads are expected to become 18.7 million by 2030, according to August 2019 data from the Edison Electric Institute. By then, 3.5 million EVs will be sold annually, representing 20% of U.S. new car sales. And that forecast could be accelerated by over 60 new models of light-, medium- and heavy-duty electric vehicles expected by the early 2020s, Hledik added.
“But the challenge may not wait until that many customers have EVs,” he said. “It can happen if one in three customers on the same distribution feeder has an EV.”
“This is the time for piloting programs so when penetrations reach the tipping point, utilities are ready to deploy passive and active demand response programs.”
Principal, The Brattle Group
This is the beginning of the transportation electrification needed to decarbonize the economy, and the utilities that see the urgency in managing this load are moving to TOU rates, Hledik said. “Twenty or more utilities offer some kind of EV-specific TOU rate to encourage EV charging when it is most beneficial to the system.”
A TOU rate that rewards EV owners for voluntary charging reductions is considered “passive” DR because the utility has little control over customer choices, he added. In “active” DR programs, customers are rewarded for giving utilities limited direct control of their charging during peak demand events.
With EV adoption still low, the value proposition favors managing EV charging with TOU rates, Hledik said. “There is no significant cost in a new rate, and it can immediately move some charging load to low off-peak rates. It might even attract customers to EVs, which would add new load to absorb more of utilities’ off-peak low-cost renewables overgeneration.”
Sacramento Municipal Utility District (SMUD) is a U.S. leader in addressing the rise of EVs, with an estimated 12,000 in its service territory, but they “don’t anticipate having to develop an EV demand response program,” SMUD spokesperson Lindsay Vanlaningham told Utility Dive in an email. Over 5,000 EV owners use SMUD’s EV TOU rate and charge after midnight.
Very few utilities see the need to confront distribution system reliability issues from EV charging with large-scale active DR at current adoption levels, Hledik acknowledged. But with growth clearly coming, “this is the time for piloting programs so when penetrations reach the tipping point, utilities are ready to deploy passive and active demand response programs.”
A small New England pilot, led by DER provider ReVision Energy for Unitil Energy used distributed resources to address peak demand issues and revealed the need to know more about EV charging as active DR.
“During a curtailment event in July, every enrolled stationary battery was ready to go and responded and none of the EV chargers responded because none had vehicles plugged in,” ReVision CEO Fortunat Mueller told Utility Dive.
“That is an issue,” Rocky Mountain Institute (RMI) Mobility Practice Manager Chris Nelder told Utility Dive in an email. “It is one of the reasons the Pacific Gas and Electric (PG&E)-BMW pilot of EV-charging-as-DR combined participating vehicles with second-life EV batteries in a stationary storage installation.”
“Customers may be willing to exchange control of their chargers with the utility for a lower electricity rate if they are guaranteed a full charge when they need it and can opt out if necessary.”
VP and Chief Innovation Officer, Green Mountain Power
But PG&E’s collaboration with BMW demonstrated the limit of shifting EV loads. “Over 18 months, from July 2015 to December 2016, BMWs and recycled batteries responded to 209 demand response events,” PG&E spokesperson Ari Vanrenen told Utility Dive in an email. But the 100 participating EVs provided 20% of the response and 80% was from the batteries.
The pilot showed EVs are “a partially flexible load” and can be used as a “grid resource, which could ultimately lead to cost savings associated with operating and maintaining the grid,” Vanrenen said.
And more utilities are exploring that potential.
Avista’s three-year pilot in Washington State involving about 200 customers “successfully shifted up to 75% of its EV charging load to off-peak hours,” Avista Electric Transportation Engineer Mike Vervair told Utility Dive. But it had difficulty maintaining Wi-Fi connectivity with its charging stations, which could limit the cost-effectiveness of a large-scale program, Vervair acknowledged.
Vermont’s Green Mountain Power (GMP) may have the most successful utility-run EV-charging-as-DR program to date. Customers in its service territory who buy EVs get a free level 2 smart charger. In return, they allow the utility to access it during DR events to reduce, delay or shift charging.
“There are 405 chargers in the program now and many more coming,” GMP VP and Chief Innovation Officer Josh Castonguay told Utility Dive. “Events are called a day in advance and, on average, five times to seven times per month.”
GMP has had “as much as 80% of participating chargers in use during some DR events,” Castonguay said. “Amazingly, almost 0% of customers opt out if they are plugged in when an event is called.”
A new GMP pilot will test “an EV-specific TOU rate” of about $0.12/kWh off-peak and $0.23/kWh on-peak against “an anytime rate of about $0.13/kWh” for giving GMP charger control during peak events, he added.
“Customers may be willing to exchange control of their chargers with the utility for a lower electricity rate if they are guaranteed a full charge when they need it and can opt out if necessary,” Castonguay said. “The pilot will reveal whether they prefer a self-managed EV-charging-as-DR model with a TOU rate or a simple utility-managed model.”
GMP modeling shows distribution system infrastructure impacts from 60,000 EVs in GMP territory in 2028 “do not create system-wide issues,” Castonguay said. “But it is clear a cluster of EVs charging at the same time in a local area could cause a service transformer issue.”
TOU rates may not address clustered charging because it can occur when rates are lowest. But with active control of the chargers, GMP could sequentially stagger the charging. “As one vehicle is charged to 100%, others would be charged to 50%, and as one completes charging, another could be ramped up.”
Coming cluster solutions
To attack the cluster charging issue, some utilities are planning to add active EV-charging-as-DR programs to passive TOU rates.
Utilities are beginning to see the need to avoid the costs of distribution system infrastructure upgrades, Brattle’s Hledik said. And meeting local distribution system demand spikes by actively moving the load to when it can be met with off-peak wind and solar overgeneration could increase the programs’ value.
Clustered charging is coming fast, and not just in residential neighborhoods, Alliance for Transportation Electrification Executive Director Phil Jones agreed. “Big loads from medium- and heavy-duty electric vehicles now being introduced in some urban areas are going to add big load spikes.”
In such a fast-changing market, “the applicability of and mechanisms for engaging in demand response are also evolving,” San Diego Gas and Electric (SDG&E) Clean Transportation Business Development Advisor Jaron Weston told Utility Dive in an email.
“Many people just want to get the cars on the road, but it will be much more expensive and difficult to do the work to turn them into grid assets if that is an afterthought instead of a first principle.”
VP for Energy Market Operations, Enel X
SDG&E’s Power Your Drive program has installed approximately 3,000 level 2 charging stations at workplaces and multi-unit dwellings. Its time-varying rate pilot, which sends hourly price signals to drivers, is widely seen as the leading EV-specific price signal design.
It is now studying demand reduction incentives for “future rates and infrastructure programs,” Weston said. The TOU rate program’s “real-world data about EV charging and demand response” will guide “careful planning and analysis” of future DR programs.
Across the country, a group of Maryland utilities are planning to test both EV-specific TOU rates and utility management of chargers to see which obtain the best results.
A pilot with active and passive DR programs from Pepco Holdings, Baltimore Gas Electric and Potomac Edison was approved by Maryland regulators in January. “In addition to new time varying pricing, each utility will initiate DR events during peak demand periods to understand EV driver behaviors,” Pepco Holdings Smart Grid and Technology Project Execution Manager Jason Tucker told Utility Dive.
In a small 2014-2015 pilot to test-manage charging through TOU rates, “the vast majority” of customers saw the price advantage in charging during lower-priced periods, Tucker said. Because the new active program will not reward participation, “it will show if customers respond to called DR events without a price incentive” and “could lead to new DR incentives, like those used in Pepco’s other demand management programs.”
Both Pepco’s Maryland and New Jersey territories are expected to have over 300,000 EVs by 2025, Tucker said. “That charging load could be a risk to our systems, particularly where there are charging clusters on a residential transformer. We don’t want to declare ‘no-charging’ times or face new infrastructure costs, so we are trying to shift charging behavior.”
Pepco’s plan is to “use passive incentives to change customer behavior where we can, and active demand response to reduce level 2 charging load where they don’t opt out,” he added. Both may become “tools in our toolkit” and part of “planning processes for years down the road.”
Planning now is critical because bringing customers into managed charging programs is a process, Smart Electric Power Alliance Principal of Transportation Electrification Erika Myers told Utility Dive. “If we wait until tens of millions of EVs are on the road, it may be too late.”
Plan now, earn later
DR’s biggest value potential is as “a service bid into the wholesale market,” RMI’s Nelder said. But programs that aggregate chargers remain small and increased participation will only come “if distribution utilities offer compensation for providing DR.”
EV charger manufacturer Enel X compensates charger purchasers for participation in the California Independent System Operator’s DR program and has aggregated about 40 MW of DR potential. Charger provider EV Connect has aggregated about 2 MW of DR potential for utilities. Some EV manufacturers, including BMW and Honda, are beginning to aggregate and compensate EV buyers for EV-charging-as-DR programs.
“Regulators need to create incentives, tariffs and market opportunities,” RMI’s Nelder and Enel X VP for Energy Market Operations David Schlosberg agreed.
“As EV penetrations rise and more ISOs and RTOs become involved, planning and market rules for aggregated EV charging must be addressed.”
Executive Director, Alliance for Transportation Electrification
The point of planning is to make transportation electrification “intentional from the start,” Schlosberg said. “Many people just want to get the cars on the road, but it will be much more expensive and difficult to do the work to turn them into grid assets if that is an afterthought instead of a first principle.”
“More state commissions need to require utilities to plan for transportation electrification in their long-term processes,” Jones, a former Washington utility commissioner, said. “As EV penetrations rise and more ISOs and RTOs become involved, planning and market rules for aggregated EV charging must be addressed.”
Where penetrations remain low, confronting the challenge “is not urgent,” but EV-charging-as-DR “will become a very lucrative option for utilities in the future,” SEPA’s Myers said. “They need to make sure the toolbox is ready. Every solution needs to stay on the table, even as more innovative technologies and new ideas emerge.”