Utility Dive, June 2019: At least 38 utility-run charging pilots and projects are in place, and interest in managed charging, primarily to avoid the capital costs of preparing their systems for higher peak loads and to engage customers, is growing, a SEPA survey found. “As we add more distributed energy resources and move to a distributed, electrified, decarbonized system, control of a flexible load is becoming more valuable,” Josh Castonguay, Chief Innovation Executive, GMP PG&E’s proposed vehicle grid integration (VGI) valuation framework is designed to help utilities develop that strategy. It addresses the management of electricity flowing one way, grid to vehicle (V1G), and the management of electricity flowing two ways, grid to vehicle and vehicle to grid (V2G).
The power demand from the 20 million electric vehicles (EVs) expected to be on U.S. roads by 2030, up from today’s 1.1 million, could overwhelm the nation’s grids. But the coming EV load could deliver great value to utilities and their customers if it is shifted away from high-priced peak demand periods. That would increase utilities’ electricity sales without adding stress to their grids, while also lowering drivers’ charging costs. Investing in the communications systems and planning needed to properly manage charging can deliver transportation electrification’s full value, stakeholders told Utility Dive.
EVs are the biggest “electric load opportunity for utilities” since the 1950s air conditioning explosion, a May 2019 Smart Electric Power Alliance (SEPA) study reports. But without proper planning to integrate that load, “EVs could lead to grid constraints and increased transmission and distribution peaks” that require new “peaker plants, unplanned grid upgrades, and other costly solutions.”
“There is already adequate charging infrastructure technology to incorporate real-time pricing, and use price signals to shift charging from peak demand periods to times when utilities have renewables over-generation,”
Proper planning and investment now will allow utilities to manage the new load and use EVs as “grid assets” to “align and balance” supply and demand, and make demand more “flexible,” SEPA Principal of Transportation Electrification and study lead author Erika Myers told Utility Dive.
Utilities can be “uniquely positioned” to manage charging to serve customers and the grid if they “take critical proactive steps before EV adoption rates accelerate,” Myers said. A framework developed by Pacific Gas and Electric (PG&E), which faces the biggest EV load of any U.S. utility, shows utilities and other stakeholders in the shift to transportation electrification how to identify and seize the value in this fast emerging market.
The shift of petroleum-powered transportation to electric transportation “could, worst case scenario, more than double electricity demand,” global energy consultant DNV-GL’s Global Energy Storage Segment Leader Davion Hill told a WindPower 2019 audience May 21. “It won’t happen all at once, but there is a huge demand to accommodate.”
With the electrification of trains, trucks, buses and other vehicles, the coming load could be overwhelming, Hill added. “But worst-case scenarios assume transportation electrification would happen without optimizing the grid, and there are ways to optimize. Managing the number of cars charging, and when they charge, will determine the real load.”
The threat to the grid represented by EV growth will not be due to a lack of the electric vehicle supply equipment (EVSE) used for charging. An estimated 9.6 million EV charging ports will be needed by 2030, according to the Edison Electric Institute, but 2018’s 1.2 million North American charging ports will grow ten times to over 12.6 million by 2027, according to Navigant.
“Managed charging programs have been smaller than other demand response programs, limiting EV driver benefits … But EVs are going to scale, and utilities need to have a managed charging strategy that will deliver value.” Erika Myers, Principal of Transportation Electrification, SEPA
Private sector EV or EVSE manufacturers could manage the coming load by aggregating their customers to provide demand response services to utilities, SEPA reported. “There is already adequate charging infrastructure technology to incorporate real-time pricing, and use price signals to shift charging from peak demand periods to times when utilities have renewables over-generation,” DNV-GL’s Hill agreed.
A utility with sufficient communications and control technology could aggregate all EV drivers in its territory, a much more significant load than any one company’s customers, SEPA reported. And as EV ownership rises, managing that large load can significantly impact system, driver and customer needs.
“It makes sense for utilities to own chargers and manage charging on their distribution grids,” Hill said. “They need to do it, to benefit and protect their systems and their customers.”
“Passive” charging management influences customer behavior through time-of-use (TOU) rates, real time pricing or other price signals, SEPA reported. These or other incentives would reward customers for charging when it serves the system and impose costs for charging when it burdens the system.
“Active” charging management can curtail or increase load through remote adjustment of EVSEs to control when or how fast the car is charged, SEPA reported. Not all EVSEs can be actively managed but interest is spiking.
The percentage of manufacturers delivering EVSEs with active management capabilities jumped to 63% in early 2019, from 33% in 2017, SEPA reported. The number of software platforms utilities can use to actively manage charging stations or vehicles more than tripled from 2017 to early 2019.
At least 38 utility-run charging pilots and projects are in place, and interest in managed charging, primarily to avoid the capital costs of preparing their systems for higher peak loads and to engage customers, is growing, a SEPA survey found. “As we add more distributed energy resources and move to a distributed, electrified, decarbonized system, control of a flexible load is becoming more valuable,” Josh Castonguay, Chief Innovation Executive, GMP
Legislatively-initiated policy trails utility-led initiatives in managed charging, North Carolina Clean Energy Technology Center (NCCETC) Senior Manager of Policy Research Autumn Proudlove, lead author on the Center’s EV policy quarterlies, told Utility Dive.
“A few bills would require utilities to file tariffs that encourage off-peak charging, usually as part of broad grid modernization legislative directives,” Proudlove said. “But most managed charging policy is utility-driven, through state commissions.”
Managed charging policies in 2019 include regulatory action on Ohio’s PowerForward grid modernization planning, Illinois legislation directing regulators to move transportation electrification ahead, and orders from Minnesota, Vermont and Maryland regulators for utilities to expand transportation electrification planning, NCCETC reported.
But one utility initiative stands out.
PG&E’s value framework
A framework created by PG&E that structures the design and implementation of a managed charging program keeps utility costs low, compared to the benefits.
“Managed charging programs have been smaller than other demand response programs, limiting EV driver benefits,” SEPA’s Myers said. “But EVs are going to scale, and utilities need to have a managed charging strategy that will deliver value.”
PG&E’s proposed vehicle grid integration (VGI) valuation framework is designed to help utilities develop that strategy. It addresses the management of electricity flowing one way, grid to vehicle (V1G), and the management of electricity flowing two ways, grid to vehicle and vehicle to grid (V2G). The framework “methodically maps the costs, benefits, and opportunities essential for a utility to develop a strategy based on the value of managed charging,” Myers said.
PG&E defined “seven key dimensions” through which the value of VGI use cases can be understood, SEPA reported. It is like a “decision tree” that allows all stakeholders to understand where their efforts are best directed. The first dimension is “sector,” which is whether the load is from a residential charger, a 6.6-kW Level 2 charger, or a 120-kW Direct Current Fast Charger, PG&E VGI and innovation specialist Karim Farhat told Utility Dive. The second dimension is “application,” which is the service the utility expects from managing the EV. “Type” is whether the utility will manage a V1G or a V2G power flow. These first three dimensions “determine how the benefits and costs of managed charging are created and where the value comes from,” Farhat said. “The other three dimensions are about the VGI business model, which is not value creation, but value enablement or value capturing.”
“Approach” is whether the utility uses passive or active charge management. “Resource” and “Alignment” are both about whether the EV and the charging station owners’ objectives are the same, like a fleet owner and an EV fleet, or separate, like an EV owner and a charge station host.
“Technology,” the seventh dimension, “is the foundation hardware and software that supports all six dimensions, but the VGI conversation should focus on value, not technology,” Farhat said. “The two objectives are to identify how a use case fits in each dimension and to identify where value is created and captured or not captured.”
There might be “significant value” in the sector, application and type dimensions for a use case like deploying managed charging to defer a distribution system infrastructure expenditure, he said. But “if the approach is not optimal or if the resource is fragmented, or if there is misalignment, the value potential to the utility and the grid may go unrealized.”
A SEPA example: A residential EV’s charging (Sector) can be shifted (Type) to reduce the utility’s peak demand and lower the customer’s bill (Application) by the utility setting the EVSE on its lowest TOU rates (Approach) if the charger and vehicle are owned by the customer (Resource and Alignment).
Today, the “low hanging fruit” for utilities are benefits from use cases they can implement now, like load shifting, and there is no point in major efforts where value is not yet clear, like communication protocols and pathways, Farhat said. “The underlying logic is a focus on what the framework shows about a technology’s value.”
Managed charging “is a concept that encompasses multiple products, technologies, players, and assets that together will deliver the promise of grid, driver and customer benefits,” Farhat said.
Managed charging in action
Three utility-managed charging pilots highlighted by SEPA reveal use cases with available value.
PG&E’s collaboration with BMW and software platform provider Olivine demonstrated the feasibility of shifting EV loads. Over 18 months, BMWs and recycled batteries responded to 209 demand response events and met performance requirements for 90% of them, PG&E reported. The pilot showed managed charging can “increase the use of renewable energy and prevent solar curtailment by shifting charging to periods of over-generation,” Farhat said.
In a three-year Avista pilot in Washington State involving about 200 residential and commercial customers, the utility “successfully shifted up to 75% of its EV charging load to off-peak hours without customer disruption,” Avista Electric Transportation Engineer Mike Vervair told Utility Dive.
Avista installed, owned and maintained the EVSEs, but it had difficulty maintaining Wi-Fi connectivity with the EVSEs. That could compromise the cost-effectiveness of scaling such a program, Vervair said. “Communicating with the EVSE through a smart meter network that uses utility communications infrastructure is not available now, but it is where we need to go.”
“Car buyers like me are postponing purchases of gasoline-powered vehicles, and that market is likely to drop off faster than anybody expects, which means the load problem is going to ramp up faster than anybody expects, and solutions will be needed soon,” Davion Hill, Global Energy Storage Segment Leader, DNV-GL
Vermont’s Green Mountain Power (GMP) did not encounter the same difficulties in a 200-customer, two-year pilot that went utility-wide early this year and now has about 300 participants, GMP Chief Innovation Executive Josh Castonguay told Utility Dive.
Through its Virtual Peaker software platform, GMP managed charging for a variety of EVSEs to accomplish three objectives of value, Castonguay said. It turned down or turned off charging during its evening peak demand period, ramped up charging to use midday solar over-generation and did energy arbitrage for customers by moving charging to the lowest-cost time periods.
“As we add more distributed energy resources and move to a distributed, electrified, decarbonized system, control of a flexible load is becoming more valuable,” he added.
“To meet the future charging need, EV infrastructure investments are going to be on the order of billions of dollars,” SEPA’s Myers said. “But that investment must begin now to have adequate infrastructure when it is needed, and there is no evidence utilities, EV and EVSE manufacturers, or other stakeholders in the power system’s future are investing enough.”
DNV-GL’s Hill agreed. “Car buyers like me are postponing purchases of gasoline-powered vehicles, and that market is likely to drop off faster than anybody expects, which means the load problem is going to ramp up faster than anybody expects, and solutions will be needed soon.”
The report’s “number one takeaway” is that “the time to act is now and we can’t afford to wait until tens of millions of EVs are on the road,” Myers said. “It seems complicated, but of all the challenges the utility industry faces, this could potentially be one of the easiest to solve because this is still a relatively new and small industry and the stakeholders know what is needed.”