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The Future Of Distribution Networks

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...

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  • Aug 30, 2022

This item is part of the Electrification of Transportation - August 2022 SPECIAL ISSUE, click here for more

In a timely blog posted on 27 June 2022, Meredith Fowlie, a professor at Univ. of California, Berkeley Energy Institute points out that “The local power lines and substations that deliver electricity to our homes and businesses may seem dull and pedestrian. But this infrastructure has a critical role to play in the clean energy transition. If electric vehicles (EVs) and building electrification drive electricity demand peaks into uncharted territory, system upgrades will be needed.” She adds,” How many, and at what cost, has been impossible to assess given a dearth of data.”

Referring to the research by Elmallah, Brockway, and Callaway (EBC) who examined circuit-level data on load hosting capacity with neighborhood-specific estimates of the load increases for one large investor-owned utility, Pacific Gas & Electric Company (PG&E), one can see what happens at the local distribution level “…  as more electric cars and electric heating appliances plug into the grid.” It is not an academic question and as she points out billions of dollars of investment will be required to maintain, upgrade and modernize the network – depending on how well or poorly this growth is managed.

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The 3 researchers considered each of PG&Es more than 3,000 feeders to determine “… the capacity for local distribution infrastructure to absorb electrification-induced load increases. Given how hard it is to predict when/where people will charge their EVs, or how fast the residential electrification situation will actually unfold.” EBC considered a range of scenarios while Fowlie highlights a few of their major conclusions in her blog post, highlighted (and edited) below.

First: EVs drive the pace of distribution system upgrades

Fowlie points out that California’s EV targets assume that PG&E territory reaches 3.1 million EVs by 2030 and 12.5 million by 2050. As a point of reference, PG&E’s service territory covers roughly half of California – so as a rough guess, one can double these numbers to get a sense of how many EVs may be on the roads in the state by 2030 and 2050, and the demand they will impose on the network.

Fowlie estimates “… that we will need between 95 and 260 feeder upgrades per year between now and 2030. That’s about triple the pace of projects that PG&E has planned for through 2025.” Again, one should roughly double the number for California as a whole.

Second: Distribution system upgrades cost real $$$

Fowlie writes that “… upgrade requirements in PG&E territory will add up to approximately $1 billion between now and 2030” and probably close to $5 billion by 2050. That, of course, is music to the ears of investor-owned utilities (IOUs), who like nothing more than adding more to their asset base on which they can earn an allowed rate-of-return.

How, when, and where EVs are charged matters

Notes: Upgrade needs for PG&E distribution circuits through 2030 and 2050, respectively. There are 3043 circuits in total. The DR/Standard/More Commercial EV scenarios assume coordinated night-time residential charging; 67% access to residential charging; 50% access to residential charging, respectively. The demand response (DR) EV scenario smooths residential nighttime charging from 10pm to 5am.

Third: Commercial EV charging holds promise

According to Fowlie “… dialing up the share of EV charging that happens at commercial locations does not increase distribution grid costs. You can see this by comparing the upgrade numbers across the “standard” scenario – where 67% of EV drivers are assumed to have access to home charging – and the “more commercial” scenario where 50% of drivers have access to at-home charging.” She writes, 

“This (result) surprised me because it’s assumed that charging at commercial locations will happen during the day, whereas residential charging happens at night. I had thought that daytime charging would be more constrained because it’s more likely to coincide with peak loads. But these data suggest there’s some excess capacity on commercial circuits.”

What can be done to alleviate the impact of these new and growing loads on the distribution network? Will rooftop solar come to the rescue? Could more rooftop solar reduce the need for distribution cost upgrades?

The simple answer is that “…more residential PV without storage has limited impact on system upgrade needs.”

“This is not surprising given that much of the heating load and residential EV charging is assumed to happen at night. Distributed solar plus storage could reduce the need for distribution system upgrades.”

More important, Fowlie adds,

“But could it really make sense to invest in distributed batteries to charge our EV batteries? Back-of-the-envelope calculations say no – probably better to bite the system upgrade bullet so that we can plug our EVs into the grid.”

What else can be done? Will Smart EV charging come to the rescue? “The researchers consider a stylized demand response (DR) scenario that evenly distributes at-home vehicle charging between the evening hours of 10 pm and 5 am. They find that this kind of coordination reduces upgrade requirements and associated costs. Could costs be further reduced with more targeted demand response programs?”

“The answer is almost certainly yes. Remember that distribution system costs are no higher when EV’s plug into commercial circuits during the day (versus residential circuits at night). A big advantage of daytime charging is that it can be coordinated to soak up solar PV production (and low wholesale prices).  Smart coordination of commercial/at-work charging could deliver bigger system-wide cost savings.”

Fowlie’s insights based on the research by Elmallah, Brockway, and Callaway is revealing. It suggests that the added strain that can be expected to be inflicted on the local distribution networks across the globe as electrification of transport, heating and everything else gains momentum over the years is significant.

Research by others suggests that, all else being equal, profit-motivated IOUs have perverse incentives to over-invest in upgrades and – if allowed by hapless regulators – prefer sub-optimal charging patters by EV drivers since this increases the need for network upgrades, which means they will end up with even more assets in their regulated ratebase.

There is a lot at stake and this editor’s view is that the IOUs will get more of what they want if the regulators are not alert and vigilant. Given the asymmetry of resources between the two, the chances are that the former will prevail. n

Fowlie, Meredith,  “What Will Electrification Cost (the Distribution System)?”,  Energy Institute Blog, UC Berkeley, June 27, 2022,


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