Why utilities need to respond now to the EV boom
Accelerating growth forecasts for electric vehicles have energy analysts urging utilities to start planning for their impacts on the grid today.
By 2021, Bloomberg New Energy Finance (BNEF) forecasts U.S. electric vehicle (EV) sales could reach 800,000 annually. By 2025, the Edison Electric Institute, a utility trade group, estimates there could be 7 million zero-emission vehicles on U.S. roads.
“EV sales in the U.S. have been growing at a compound annual growth rate of 32% for the past four years,” said Chris Nelder, electricity practice manager at the Rocky Mountain Institute (RMI). “2017 monthly sales data suggest that rate is accelerating. Under some reasonable assumptions, there could be 2.9 million EVs on the road in the U.S. within five years.”
That many EVs could add “over 11,000 GWh of new load to the U.S. power grid,” said Nelder, co-author of RMI’s new report, “From Gas To Grid: Building Charging Infrastructure To Power Electric Vehicle Demand.”
EVs are only 1% of total vehicles sales today, “but 11,000 GWh of load is about $1.5 billion in annual electricity sales that utilities may need to accommodate within their current planning horizons,” Nelder said. “Are utilities and system operators ready for that?”
Failing to prepare for EV growth with grid upgrades and rate design reforms could leave utilities “flat footed” when this new load materializes, Nelder said. But if utilities reform their rate designs and infrastructure planning to account for EV growth, they could spur more deployment than than the most optimistic of forecasts and deliver savings even to customers who don’t own the cars themselves.
Ratepayer benefits of EVs
The pressure to prepare for EV growth is felt by many in the power sector, said Bill Boyce, electric transformation supervisor for the Sacramento Municipal Utility District (SMUD).
The BNEF forecast shifted the attitude of the utility industry and marketplace “from ‘if’ to ‘how soon’” EVs would come to dominate, he said.
Using the BNEF numbers, the RMI paper reports U.S. EV sales will be 500,000 in 2020, just over 1,000,000 in 2022, and 2,000,000 in 2025. Growth will accelerate because “an EV is a good investment,” Nelder said.
Utility rate design will be crucial to that investment decision, said Jim Lazar, senior advisor at the Regulatory Assistance Project. Once vehicle-to-grid charging technology becomes widespread, the opportunity for EV rate arbitrage will be “virtually unlimited,” he said.
With the proper time-varying rates, an “essentially unlimited” number of EVs could be charged with low-priced power from midday solar generation or nighttime wind and discharge at a profit to EV owners during peak demand periods, he said. “And a lot of utilities are moving toward that.”
But having more EVs on the system could have benefits even for utility customers who do not own them, Lazar said. Higher utility payments from EV owners could help cover a greater proportion of grid costs, lowering bills for everyone else.
That “ratepayer benefit,” Lazar said “depends on getting people to charge when demand on the grid is low.” That, in turn, depends on time-varying rates, or TVR.
“Without TVR, much of the benefit is limited to EV drivers,” Lazar said. “With TVR, non-EV-driving ratepayers also benefit.”
If utilities continue to move toward TVR, assumptions about EV growth are likely to be correct, Lazar said, “and we will need charging infrastructure.”
“That leads to a discussion about rates and infrastructure ownership,” he said.
Barriers to deployment
The single biggest threat to realizing the benefits of the forecasted EV adoption is inadequate charging infrastructure, Nelder said.
The vast majority of EV charging — up to 85% — is now done at home with level one (L1) 120-volt outlets. That takes 10 hours or more. The bulk of the charging will likely evenutally be done at homes, workplaces, and commercial and public venues through level 2 (L2) 240-volt chargers that can provide 80 miles of range in 2 hours to 5 hours.
A small proportion of EV charging will be done through DC fast chargers (DCFC), which draw 240 volts and can provide 80 miles of range in 3 minutes to 24 minutes.
DCFCs are expensive and costs will likely keep them from wide deployment, Lazar said, but “a limited number is necessary for long distance drives.”
Getting those chargers deployed is likely to be a challenge. Because DCFCs can use 50 kW to 400 kW, they can cause a sharp spike in an otherwise low utilization profile. That drives up the demand charge for DCFC owners, so much that the use of DCFCs is typically uneconomic today.