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Utilities Moving Towards Bidirectional Flows

Fereidoon P. Sioshansi, Ph.D.'s picture
President, Menlo Energy Economics

Dr. Sioshansi is President of Menlo Energy Economics, a consulting firm based in San Francisco, California, advising clients on the rapid transformation of the electricity sector and emerging...

  • Member since 2004
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  • Jan 7, 2023
The days when utilities produced lots of power in large thermal central plants and transmitted it down the wires to customers have already changed as the electricity generation mix gradually shifts toward more renewable generation, both utility-scale and distributed – the latter as consumers produce, store, and consume some of what they need from solar panels on their roofs. Many of these prosumers generate more than they need during the sunny hours of the day – which they can feed into the grid and/or store in batteries or electric hot water tanks – if they have one – for later use. But the biggest and most significant behind-the-meter (BTM) asset that is being acquired in large numbers are electric vehicles (EVs), which are nothing but big batteries on wheels.

As is currently happening with small-scale storage devices, large EV batteries are ideally suited for storing energy from the rooftop solar panels or the grid when supplies are plentiful and prices are low. Why not release some of the stored energy back to the grid after the sun has set – when peak demand occurs,and prices tend to be high?

The technology to do this, vehicle-to-grid (V2G) is well-known but not currently well-developed. That, however, is about to change, promising to reverse the flow of electrons from customers’ BTM assets to the grid. 

As reported in the 2 Nov 2022 post in Utility Dive, the California Public Utilities Commission (CPUC) approved an agreement reached on 20 Oct among Pacific Gas & Electric Company (PG&E), the Vehicle-Grid Integration Council, or VGIC, Electrify America – a major EV charging company – and the CPUC’s Public Advocates Office that offers a compensation mechanism for commercial electric fleets and bidirectional chargers that can provide much needed services to the grid while enhancing reliability. 

In praising the CPUC’s approval, Ed Burgess, VGIC policy director, said, “The CPUC’s decision is a strong step forward for Californians and in support of the state’s grid, implementing the nation’s first dynamic export rate for EV charging customers,” adding,

“As ever-greater numbers of EVs hit the roads, this innovative rate option will allow EV owners to further benefit from their investment in clean transportation.”

The V2G rate is expected to be implemented “as soon as practical” but not later than Oct. 2023, according to the agreement reached between the parties. Participating EV owners will be compensated for exports to the grid based on day-ahead hourly pricing. It is not clear why the same ruling does not apply to all utilities in California.

To encourage enrollment special incentives will be offered for the first year to electric school buses and larger vehicles based on the battery’s size. EV owners and EV charging operators who are able to discharge up to 100 kW are eligible for $1,800; electric buses will receive $3,150 in incentives; those with larger batteries can get more – the incentives can total $6,560 in some cases.

Electric school buses (photo) offer exceptional opportunities not only because of their large batteries but also because they run on predictable schedules – usually sitting idle during the sunny mid-day hours, making them prime candidates to store cheap solar energy while allowing some of the excess stored energy to be fed back into the grid in late afternoon/early evening hours. Large fleets of commercial vehicles such as delivery vans and trucks also have large batteries, but they are extensively used during most hours of the day (and night) with inflexible schedules. They may be charged late at night or in early morning hours but may not be able to discharge during early evening hours.

Mike Gazda, a spokesperson for PG&E, told California Current that the project will initially focus on two-way vehicle chargers for electric buses. PG&E said it is working to “prepare the grid for 12,000 GWh of EV-related electric load and to improve processes to enable rapid, safe EV energization and interconnection” by 2030.

PG&E is currently home to the largest EV market in the US, with about 420,000 EVs in its service territory. It said that it could have as many as 2 million EVs charging from the grid and discharging back when needed. To get a sense of the scale of the California’s EV market, roughly double these numbers since PG&E covers roughly the northern half of the state.

While there are many more privately-owned EVs, electric buses and commercial fleets offer much better opportunities for scaling up V2G programs not only because of their much larger batteries but also because their operational patterns are much more predictable.

As the electrification of the transport sector gains momentum, the opportunities to manage when, where, and how they are charged – and potentially discharged – will become critical. If poorly managed, the massive EV load will most likely crash the grid. If properly managed, it will help the integration of renewables into the grid. 


Jim Stack's picture
Jim Stack on Jan 9, 2023

The discharging only as needed should be done by a control signal from the GRID operators. This can also be controlled along with Virtual batteries from all the home Solar Battery storage as was done by Tesla in the summer of 2022. It can be used just as needed with plenty extra to spare. As long as the pay per kWh is far like the $2 a kWh paid over that summer everyone will benefit. 

Barry Jones's picture
Barry Jones on Jan 14, 2023

Your last sentence regarding the proper management of load (and voltage) is interesting in context of V2G. What does that look like when you potentially have thousands of resources, varying behaviours, weather, battery life/quality, etc.., all playing into this scenario. Do we rely on V2G in summer and other resources in winter? Who decides? That should be left up to local and regional markets and privatization. This is also a segue into the discussion of regulation - one that is nearly always missing from these discussions. Reduction in regulation provides greater investment incentives to bring capital and process efficiencies which ultimately reduce cost per kWh. Therein lies the problem. Politicians, biased media, activist groups, and governments are involved. Denmark for example has the highest cost per kWh due to choice factors such as reliance on intermittant sources of energy (wind, EV, etc...). But that is only one aspect. Denmark's kWh is coupled with high taxes supporting vast social programs. Danes pay more in taxes on energy than they do for the production, transmission, and distribution of electricity. And not far behind are Germany, Spain, Uk, and other such countries. And even with such regulation, there's virtually no narrative regarding the impact of expired toxic battery components or sourcing such as slave labor in African mines. Those discussions are quietly missing. So the discussion of cost per kWh is obscured in policy. California is no different. While it's interesting to envision and wonder about energy types, sources and a clear kWh cost discussion, it's nearly impossible to do with all the different cooks in the kitchen.

Fereidoon P. Sioshansi, Ph.D.'s picture
Thank Fereidoon P. for the Post!
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