When thinking about the electric vehicle, it might be helpful to remember the fable of the tortoise and the hare.
While it’s hard to recall today, the exploding solar and wind industries went through years when both resources struggled for a foothold. Like the current electric vehicle (EV) market, those industries built their foundations on years of steady, tortoise-like growth, gaining scale and know-how to get to their current expansions.
After years of sluggish growth, it’s clear that electric vehicle growth is no hare — EVs still represent well under 1% of the total transportation fleet. But a new paper suggests that the utility industry should use the EV industry’s period of slow growth to lay the groundwork for an integration of the power grid and the transportation sector.
Through the use of properly-sited charging stations and rate design price signals, utilities can stimulate the adoption of electric transportation and utilize it to build a cleaner, more resilient grid, according to “Electric Vehicles as Distributed Energy Resources,” a new report from the Rocky Mountain Institute (RMI). If they don’t, their failure to prepare could hamper the transition to electric transportation and impose more costs on drivers and ratepayers alike.
“If every light vehicle was an EV, total U.S. electricity demand would increase about 25%," said Chris Nelder, a manager in RMI’s electricity program and the paper’s principal author. "But it could be done without increasing peak generation and it could reduce the unit cost of electricity by eliminating the need to invest in peaking capacity.”
EVs today and tomorrow
Approaching anywhere near full penetration of electric vehicles is a long way off, Nelder said.
In 2015, 17.4 million passenger vehicles were sold in the U.S., but only 0.7% (116,597) were EVs,” RMI reports. The 407,136 EVs in the U.S. are just 0.16% of the passenger vehicle fleet.
The two longstanding barriers to greater EV adoption have been upfront cost and limited battery range, RMI reports. But today, carmakers may be on the verge of solving both those problems.
“Tesla and Chevrolet plan to start selling electric cars with a range of more than 200 miles priced in the $30,000–$35,000 range by 2018 (before incentives),” the paper reports.
Just how those offerings will be viewed by consumers is up for debate. ExxonMobil forecasts that EVs will account for less than 10% of new car sales globally in 2040, RMI reports. But Bloomberg New Energy Finance (BNEF) foresees that by then “long-range electric cars will cost less than $22,000, and 35% of all new cars worldwide will have a plug.”
U.S. EV sales fell 5.2% from 2014 to 2015 when gas prices dropped. But global sales grew 60% in the same period, RMI notes. And U.S. sales were up 16.5% year-over-year in April 2016, a sixth straight month of record growth.
Getting to a more meaningful level of deployment will require proactive planning now by utilities, regulators, and other stakeholders, Nelder said. Distributed energy resource (DER) aggregators, vehicle manufacturers, local elected officials, and people with influence over local building and planning must also be involved.
Wisely expanded EV deployment will offer stakeholders two key grid services, Nelder said. Intelligently managed, EVs can provide demand response or maximize the value of variable renewables by minimizing curtailment.
“If we don’t manage charging intelligently," he said, "we will not capture the benefits and we will have the worst outcomes.”
The utility opportunity
Managing EV charging intelligently means “influencing, with increasing precision, where and when EVs are charged,” the paper reports.
Doing so can provide distribution system operators with a resource that, like stationary storage, can do everything for the grid except generate electricity, Nelder said. “Everything else is about balancing. System operators either turn up a generator or reduce load. That balancing can also come from turning chargers on and off.”
In a group of five diverse states — California, Hawaii, Minnesota, New York, and Texas — RMI modeling shows the EV impact on peak load can be reduced between 20% and 90% if charging is managed intelligently.
To make the EV resource available, stakeholder cooperation on advanced planning will be necessary in three broad areas: Siting and installing chargers, devising supportive subsidies and electricity tariffs, and getting all the hardware and software support infrastructure in place.
“If utilities anticipate the load of charging EVs and plan for it proactively, they can not only accommodate the load at low cost, but also reap numerous benefits to the entire system,” the paper reports.
Those benefits, RMI reports, include significant avoided costs for new grid infrastructure. Optimized performance and extended service from existing assets would save system upgrade investments. Better integration of variable renewables would reduce curtailment, avoiding the need for new flexible natural gas capacity. That would reduce costs to limit greenhouse gas emissions and criteria pollutants.
Distribution system services obtained from EVs could eliminate transmission and pipeline system costs, improve energy security, and deliver multiplier benefits to the local community, RMI notes. Finally, getting more from existing generation and grid assets would reduce the need for new sources of ancillary services like frequency regulation and voltage stabilization.
By contrast, responding to EV loads “late and reactively” will likely cause the “worst outcomes” for utilities and for the EV market, the paper argues. Those outcomes include shorter grid infrastructure life, increased spending for fast ramp natural gas peaker turbines, reduced renewables value, a threat to grid reliability, and increased utility customer electricity costs, RMI argues.
Timeline for growth
With market penetration low and growth forecasts ranging widely, the RMI paper does not offer a timeline over which the capability for intelligent EV planning must be put in place.
“Nobody knows how quickly the deployment will happen,” Nelder said. “But we need to start thinking about this now. We can’t wait until it becomes a problem because we would incur a lot of unnecessary expense.”
At present, utilities planning for EVs make an important assumption, he said. They foresee drivers habitually coming home from work and plugging in their cars. With higher market penetrations, this could have a bad outcome.
“Only five EVs in a neighborhood, plugged in at the same time, would likely overload the distribution transformer or at least wear it out faster,” Nelder said.
Intelligent policy would give utilities incentives to work with shopping centers and workplaces. “With enough level 3 chargers in those places, people might get home needing only a 10% top off,” Nelder said. “That would allow utilities to shape more appropriate, off-peak charging through tariffs.”
Studies show EV buyers must be influenced within the first three months of ownership to charge off-peak or they will develop the habit of charging on arriving home, according to Nelder. That is why utilities, regulators, and other stakeholders must put policies, infrastructure, and tariffs in place that will drive the best car owner habits before market penetrations rise.
For any new technology, the first 1% of market share is the hardest to get but, after that, adoption accelerates, according to RMI. With range increasing, price decreasing, and car buyers becoming more aware of those advances, “electric vehicles look poised to enter the rapid-growth portion of the classic technology adoption ‘S-curve,’” the paper reports.
Winning approval for special EV rate structures takes time, Nelder noted, and charger siting and deployment will take even longer, meaning stakeholders in areas of high EV adoption need to plan now.
If we wind up without public infrastructure at workplaces and shopping centers and everybody has to drive home to charge their vehicles, we will have totally missed the opportunity,” Nelder said.
Four potential roles for utilities
California has 200,000 EVs and Gov. Jerry Brown (R) has a target for 1.5 million zero emissions vehicles by 2025. Utilities, RMI argues, can play one of four roles to help drive that 600% growth in the state and facilitate the nation’s march toward electric transportation.
Utilities could stay out of the charging business entirely and simply be facilitators. In this role, they would treat EV charging like any other load and provide “nondiscriminatory electric service when and where requested,” according to the paper.
Power providers could also manage the chargers and deliver electricity from them. In this role, they could match charging with “grid capabilities and grid needs,” RMI says.
Utilities might play a significantly bigger role if they become providers of EV charging equipment and charging services in return for a regulated cost-based payment or tariff, rounding out a third strategy. And finally, regulators see it as necessary to EV expansion, utilities could approved as exclusive providers of EV charging equipment and services in their territories.
For each role, regulators must ensure that “utility service and prices are fair, just, reasonable, and sufficient,” RMI notes.
Under the first role as a facilitator, the utility simply delivers metered electricity and a bill. “The owner of the charger is responsible for the charging equipment and for the business relationship with the EV driver,” the paper reports.
Many private sector business models could apply, but “the owner of the charging station determines how to recover the cost of the service through charges paid by EV drivers,” RMI adds.
Rates for EV users should not include demand charges because they could compromise EV growth by making level 3 fast charging prohibitively expensive, RMI cautions. Service charges to recover customer-specific costs and time-varying energy charges to recover distribution-system and power-supply costs would be more appropriate.
“The role of the regulator in rate design is to ensure that an EV customer is not treated differently from other customers,” RMI argues.
As manager, under the second option, the utility’s role would be similar to that of a facilitator. But a degree of control over the charger would allow the utility to obtain demand response services in return for tariff and cost considerations.
“The charging equipment remains privately owned, and the business relationship with the EV driver remains with the owner of the charging facility,” according to RMI.
As the provider of equipment and charging services, “the utility owns the full supply chain, from the distribution grid through to the EV charging stations,” according to RMI. “It is responsible for maintenance of the equipment and for the business relationship with the customer.”
Regulators must protect against anti-competitive practices by a regulated entity in the unregulated marketplace, the report argues. They would also set the retail rate for charging to allow recovery of the electricity supplied, the charging equipment costs, and the use of the distribution system.
“Allowing utilities and automakers to deploy and own EV charging infrastructure may be the most expedient way to get more charging stations deployed,” RMI suggests. “Automakers can build the cost of deploying charging infrastructure into their broader cost structure over longer periods of time, and at a lower cost of capital.”
Some argue utilities should be the exclusive provider in their service territories, RMI notes.
“Utilities have to be the ones because it will take a longer time and cost more than a private company will give it,” Brett Hauser, CEO of EV charger software provider Greenlots, recently told Utility Dive. “Utilities can rate base the charging infrastructure upgrades and consider what is best for the community. Private sector financial concerns will focus the infrastructure on narrower, more affluent markets.”
In California, RMI notes, regulators have reversed an earlier stance that utilities posed an anti-competitive threat to third party charging companies, allowing the state’s big three IOUs to proceed with pilot charging programs. But commissioners have sought to keep utility investment modest, scaling back an ambitious initial proposal from PG&E in October of last year.
Making utilities the exclusive charger and charging service providers could solve many of the challenges of “influencing, with increasing precision, where and when EVs are charged,” the paper reports. But, because of the threat to the unregulated marketplace, regulators should be cautious about doing so.
Nelder told Utility Dive his initial impulse was that the charging service should be left to the marketplace. But in his research he found early private sector charger providers had gone bankrupt because they didn’t have the capital to endure the tortoise-like growth in EV sales.
“A lot of chargers are sitting broken out there because of the bankruptcies,” he said.
He then saw the potential of utilities’ strong balance sheets, access to low-cost capital, and knowledge of the system. “It seemed clear utilities would be the way to get it done quickly,” he concluded.
When he sent the paper out for review, however, he found resistance to that idea. Both private charging service providers and regulatory agencies argued that past performance was not determinative.
“They said letting the private sector do the deployment would be in the best interests of the customer,” Nelder found. “There are pros and cons and there may not be a one-size-fits-all answer.”
Five utility EV leaders
In the report, RMI researchers spotlight five utilities with active EV charging programs. Utility Dive was able to get feedback from four of them.
Georgia Power’s Get Current/Drive Electric pilot will run through 2016, according to Spokesperson John Kraft. The primarily “education and awareness” program includes 11 charging islands with level 2 and level 3 chargers. It also “offers a Plug-in Electric Vehicle rate, which is built around time-of-use features,” Kraft reported.
The utility “understands distributed energy implications and potential opportunities around EVs as a distributed energy resource,” Kraft added. But “EV adoption rates and technology issues remain constraints on EVs as a significant distributed energy resource.”
On the other hand, “so long as interconnection and safety standards are met, the company welcomes additional EV charging infrastructure making it easier for EV owners to charge and go,” Kraft said.
California regulators approved Southern California Edison’s (SCE) $22-million Charge Ready pilot in January, noted Spokesperson Paul Griffo. The expenditure is for installation of up to 1,500 chargers and a supporting market education effort. SCE has already received 170 applications requesting more than 1,000 charging stations at workplaces, destination centers, multi-unit dwellings and fleet operators.
SCE-qualified participants and site hosts will own, operate, and maintain the level 2 chargers, though the utility “will offer rebates to offset some or all of the cost of the charging stations and their installation,” Griffo added. SCE will install and maintain the supporting electrical infrastructure.
If approved, a second phase would expand the program to 30,000 charging stations over five years, Griffo said.
Also in California, the San Diego Gas and Electric (SDG&E) $45 million, three-year Power Your Drive program aims to put 3,500 charging stations in place at 350 sites, beginning in 2017, according to Spokesperson Hanan Eisenman. The utility will also offer a new day-ahead, hourly charging rate to EV owners.
“No one else in the U.S. has that rate,” Eisenman said. “It is designed to maximize the use of solar at midday when it is most available.”
The utility will own and maintain charging stations provided by winners of a request for proposals now being prepared, Eisenman added. “We will buy the least-cost, best-fit technology that will accommodate the dynamic pricing designed into the rate.”
SDG&E has seen excellent cooperation in its service territory, has identified 20 locations, and is looking for more. “It is the first and largest EV charging program by a U.S. electric utility, Eisenman said. “The intent is to use EVs as a resource to optimize grid performance. Thinking about them as energy storage is something farther down the road.”
Pacific Gas and Electric (PG&E), the third and largest California IOU, proposed the most ambitious U.S. utility charger installation program to state regulators, according to Communications Representative Paul Doherty. After regulators pumped the brakes on the initial proposal, the revised plan is still being evaluated.
The state estimates PG&E needs to expand from today’s 5,000 chargers to 100,000 in its Northern and Central California service territory to support EV targets, Doherty said. To begin that effort, the utility wants to partner with private providers to install 7,500 level 2 chargers and 100 DC fast chargers.
“The plan proposes a total budget of $160 million over three years, which will have a customer bill impact of 22 cents per month,” Doherty said.
PG&E sees unique potential in EVs as a distributed energy resource (DER) that can help the utility “more effectively utilize its existing grid and keep costs for customers low despite increases in load,” Doherty said.
EVs and charging station smart technologies are unlike other new sources of load, he added. They offer both demand response capabilities that can help PG&E manage peak demand and value as stored energy that can deliver power back to the grid and improve system reliability.
Hawaiian Electric, the fifth utility included in the RMI report, did not respond to requests for comment before publication. The utility, however, asked regulators for approval last summer for 25 DC fast chargers to alleviate drivers’ range anxiety on Oahu, Maui and the Big Island, as well as simplified EV charging rates. The utility is currently testing storage-integrated chargers with Greenlots that would allow vehicles to remain at near full charge while providing grid services.
Rate structure: The key ingredient
To realize the EV opportunity before the worst outcomes become inevitable, RMI concludes, utilities, regulators, policymakers, aggregators, charging equipment and vehicle manufacturers, building owners, and elected officials must cooperate to remove barriers and support deployment.
Central to the paper’s recommendations are parameters for rate, tariff, and incentive design. “Regulators, utilities, and distribution system operators need to offer well-formed time-of-use (TOU) rates or other dynamic pricing to shift charging toward low-cost, off-peak hours,” the paper argues.
“Regulators need to create incentives, tariffs, and market opportunities that will accelerate the deployment of EVs and charging infrastructure,” it adds. “Transmission system operators need to accommodate aggregations of EVs as demand response assets.”
Customers and vehicle dealers must understand the value proposition in such rates, tariffs, and incentives. They must start EV owners toward that intelligent charging that puts the resource where and when utilities and system operators need it.
The best of rate designs to date is the one proposed by SDG&E, Nelder said. “It is the cutting edge of the EV experience.”
“A day-ahead hourly rate, together with a smart charging system, will work pretty well,” agreed Jim Lazar, senior advisor at Regulatory Assistance Project and a rate design authority. Lazar contributed to the RMI paper.
The day-ahead provision allows a smart charger to know which hours are best to meet an EV owner’s needs “to predictably and reliably minimize the charging cost,” Lazar said.
Hourly price variations provide the opportunity for owners and their smart chargers to balance the need to charge against the cost of electricity.
“Utilities proposing demand charges based on 15-minute intervals are going to have massive feedback from the customer,” Lazar said. “Anything less than hourly is impossible for customers to adapt to.”
Ultimately, Nelder said, the best use of EVs, especially as a demand response resource, will be different in different places. Charging in San Diego should be in the middle of the day “to soak up excess solar and eliminate curtailment of solar plants. Vehicles in places like North Dakota and Iowa need to be plugged in at night to avoid wind curtailment."
“All stakeholders would be wise to anticipate their respective challenges,” the paper concludes, “and take a long-term view toward their respective opportunities.”