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What Will Electrification Cost (the Distribution System)?

Coming soon to a feeder near you.

The pace of decarbonization is starting to pick up. And “green bottlenecks” are cropping up. From lithium shortages to balsa wood shortages to electricians in short supply, supply-side curve balls are threatening to slow — or hamstring– the clean energy transition.

While working to transform our grand decarbonization plans into a reality, we’re bound to stumble over costs and bottlenecks we failed to anticipate. The sooner we can identify and navigate around these complications, the better. In this spirit, a new Energy Institute working paper takes a deep dive into the electricity distribution system.


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 (albeit supporting) 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. How many, and at what cost, has been impossible to assess given a dearth of data.

An impressive research team (Salma Elmallah, Anna Brockway, and Duncan Callaway) brings great data and careful analysis to these questions. The key takeaway: If we’re serious about electrification,  our distribution infrastructure needs a lot more love and attention.

Billion-dollar blind spots

Lots of important work has already been done to assess the costs of an accelerated clean energy transition. The distribution system is conspicuously missing from most state-of-the-art modeling (see, for example, here and here) because good data are notoriously hard to find. Modeling that does incorporate it uses simplified (and top secret) parameters to approximate how demand changes drive distribution system costs, so it is difficult to gauge credibility.

The paper uses new data from California to assess the capacity of substations and distribution lines to accommodate load increases. California’s investor-owned utilities are now required to collect and release these data (thank you, CPUC).

Source: “Data Validation for Hosting Capacity Analyses” (NREL 2022)

Elmallah, Brockway, and Callaway (EBC) focus on one large utility: Pacific Gas & Electric (PG&E). They combine circuit-level data on load hosting capacity with neighborhood-specific estimates of the load increases we might expect to see as more electric cars and electric heating appliances (like those cool heat pumps everyone wants!) plug into the grid. 

For each of PG&Es >3000 feeders, EBC assess 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, they consider a range of scenarios.


There are too many interesting results to unpack in a single blog post. I’m going to focus on three:

  1. EVs drive the pace of distribution system upgrades

The picture below summarizes projected upgrade requirements across PG&E’s distribution circuits in terms of capacity and the number of circuits impacted. The graphs on the left show how EV adoption drives more upgrades as compared to building electrification on the right. Consistent with California’s EV targets, the scenarios on the left assume that PG&E territory reaches 3.1 million EVs by 2030 and 12.5 million by 2050.

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. See the paper for details.

It’s estimated 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.  

  1. Distribution system upgrades cost real $$$

To map feeder and substation upgrades into dollars and cents, the authors use PG&E reported upgrade costs. The table below summarizes these cost data. Let’s take a sentence to celebrate the transparency of these cost numbers. If readers have concerns about them, we can have a conversation about how these estimates could be refined and improved. 

Taking these cost numbers as given, the authors estimate that upgrade requirements in PG&E territory will add up to approximately $1B between now and 2030 (closer to $5B by 2050).  

  1. Commercial EV charging holds promise

These graphs also show that 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 (67% of EV drivers have access to home charging) and the “more commercial” scenario (50% of drivers have access to at-home charging).  

This 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.

 Distribution cost workarounds?

 I’m fortunate enough to be married to one of the authors of this fine paper. So I’ve been able to pick his brain about some questions I had about possible workarounds. Our kids impose a 5-minute time limit on how much time we get to spend on nerdy electricity talk. Here’s a lightning-round summary:

 Rooftop solar to the rescue?  Could more rooftop solar reduce the need for distribution cost upgrades? 


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. 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.

Smart EV charging to the rescue?

These 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. 

Amsterdam’s smart EV charging network

How to incentivize this smart charging behavior? That’s a question for the economists in the room…

Electrification route planning without a map

This research provides some great insights. But there’s clearly more work to do. And more data to share.  One issue that I’ve swept under the blog/rug is the uncertainty around these upgrade projections. The authors do the best they can with the data they have. But California utilities could provide better, more precise estimates if they updated their load integration modeling processes to capture and prepare for the most plausible electrification scenarios. 

Finally, this is just one paper about one utility service territory.  PG&E’s distribution system could look different from other parts of the country. But it’s hard to know given all that we don’t know about distribution system infrastructure and operations elsewhere! If more jurisdictions would make these data available, we’d be in a much better position to plan for the distribution-system-meets-electrification challenges ahead.

Keep up with Energy Institute blog posts, research, and events on Twitter @energyathaas.

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


22 thoughts on “What Will Electrification Cost (the Distribution System)? Leave a comment

  1. “But could it really make sense to invest in distributed batteries to charge our EV batteries?” It is this kind of thinking, monetization of societal costs, that got us here in the first place. Three points: 1) Existential threat vs bottom line; 2) Yes, total societal dollars are more, but the utilities have completely replaced their societal responsibilities with greed and cannot be trusted. Therefore, the individuals must, will, and do foot the bill for the true societal costs (eg. preventing extinction); 3) If we do nothing, our lifestyles will change to the point where our grandchildren, if there are any, will think the old folk are telling fairytales. If we consciously change our lifestyles, there can be hope. And the dollar cost cost will every penny we have!

  2. Transition into Renewables = Transition into Nothing.

    Hold on, get ready for frequent Blackouts & Brownouts, & utility bills only the billionaire Climate Czar — Captain Planey, John Kerry — can afford.

    • We’ve already had a number of days where California has run at near 100% renewable output. Still some steps to be made, but we’re almost there–the Transition is nearing completion.

  3. Thanks for pointing to the issue of helping the electrification design and install work match the distribution upgrade work. They both compete for electricians and they both can be assisted by good electrification program design focused on panel optimization.

    Below are tables of the number of miles of added charge per night and per year that can be added by different sized EV charging circuits.

    Very few of us need to size the EV circuit larger than 20 Amps to get an added 33,000 – 47,000 miles per year added to our EV batteries from home charging.

    If you feel residual range anxiety when right sizing the EV charging circuit, feel free to use stouter gauge wire (up to #6 ) to allow for easy upsizing if you want to be ready to add an electric truck to your home fleet.

    Volts, Wire gauge, Circuit Amp rating, and 7 hours, 8 hors and 10 hours per day shown below.

    Charging Hours / day
    V AWG Ckt Amp 7 8 10
    120 12 11 26 30 37 Miles added/day
    240 12 10 47 54 67 Miles added/day
    240 12 15 71 81 101 Miles added/day
    240 12 20 94 108 134 Miles added/day
    240 10 30 141 161 202 Miles added/day
    240 8 40 188 215 269 Miles added/day
    240 6 50 235 269 336 Miles added/day

    Charging Hours / day
    V AWG Amp 7 8 10
    120 12 11 9,000 10,000 13,000 Home Miles/year
    240 12 10 16,000 19,000 24,000 Home Miles/year
    240 12 15 25,000 28,000 35,000 Home Miles/year
    240 12 20 33,000 38,000 47,000 Home Miles/year
    240 10 30 49,000 56,000 71,000 Home Miles/year
    240 8 40 66,000 75,000 94,000 Home Miles/year
    240 6 50 82,000 94,000 118,000 Home Miles/year

    I hope clients, contractors, utilities and CPUC will consider the many forms of panel optimization available when designing electrification programs to preserve the climate while matching the workforce capabilities.
    A path toward equitable, rapid, low cost, low rate electrification can be designed with panel optimization as the CEC is exploring through SB 68.
    Electrify simply, so that others may simply electrify.

  4. If these estimates are approximately correct, and the cumulative cost of distribution upgrades needed to handled building and vehicle electrification will only cost $5 billion total between now and 2050, the upgrade costs will average $178 million per year over the next 28 years. Compared to PG&E’s 2021 non-fuel electric utility revenues of about $12 billion, these distribution requirements would increase the non-fuel component of customers’ bills by about 1.5% by 2050. If you add in the cost of electricity procured by PG&E and the CCAs and passed on to customers, the total bill impact would be closer to 1%. Assuming the upgrades are rate-based, the impact will be much lower than 1% in the early years and higher in the later years as the cost of the upgrades performed each year accumulates. This sounds pretty manageable, and these costs will be offset by avoided expenditures on natural gas and liquid fuels.

  5. This is an important paper that moves this discussion forward quite a bit. I expect that I’ll be using this study in upcoming regulatory proceedings. (Are the data sets available?)

    A couple of key points: While $1B sounds like a lot of money, in the context of PG&E’s rates this isn’t such a larger amount. For example PG&E is asking for about $10B to underground 3500 miles of rural lines by 2026 (part of a plan to underground 10,000 by 2030). That $10B translates to a rate increase of 3.4 cents per kWh. A $1B investment would translate to a 0.34 cents increase or between 1% to 2% of current rates. Plus the expanded demand would likely dilute the rate increase so much that rates might go down. You can see the calculations in my testimony here:

    As to whether upgrades or microgrids are cost effective, it appears that it depends on the size of the upgrades and the density of customers and load based on the cost data presented in the paper. I discuss this aspect in my testimony. Microgrids of solar+storage are highly cost effective in less dense settings. An additional question, which the paper hints at, is whether using EVs as mobile storage devices by charging at work and commercial settings during the day is a cost-effective solution as well that allows deferral of residential area upgrades?

    Finally, “smart” switches in panels may be a highly cost effective alternative. These have been discussed several times by commentors on this blog in response to Andrew Campbell’s blogs on the difficulties of upgrading a rental property to accommodate EVs and other electrification purchases. In Davis at Muir Commons there was a demonstration of how to accommodate an EV within a 100 amp panel through this strategy. This path means that distribution planners would have to change their standards from assuming all loads are on simultaneously to including customer-side measures for load management.

  6. The concept of solar plus storage for residential EV charging presents some practical challenges when it comes to both capacity and scheduling. My EV has a 64 kWh battery, and my stationary battery has a 20 kWh capacity. So, even if the EV is only half discharged, I can’t completely charge it from the stationary battery. Also, the stationary battery has an 8 kW inverter and the Level 2 EVSE draws about 7 kW. The two times that I’ve (mistakenly while fooling with the scheduling) tried to charge the car from the stationary battery it has tripped offline because it was sensing an overload condition. The battery can be scheduled in TOU mode to either discharge during “high tariff windows” or charge, from PV only or PV plus grid. Consequently, I have the battery scheduled to charge from the grid between midnight and 4 am, and the EV to charge, also from the grid, from 4 am until 6 am during the SDG&E super off-peak period. Weekends I can charge until 2 pm.

    I can see how some sort of “smart-charging” algorithm could solve this, but it would be pretty complicated.

    Another consideration is the loss in efficiency in the charge/discharge cycle. If I charge the EV from the stationary battery the I would have twice round trip losses that I would see from charging directly from PV or the grid.

  7. Just today EV manufacturers announced price hikes to their vehicles — up to 6%. Rivian and GM EV pickups averaging at about$100,000. Not too be provocative, but who will be buying these things? For awhile it was admitted that EVs were expensive, but the prices would come down. But the prices seem only to go up. Before Ford came out with the Model T in 1908 private vehicle ownership was a novelty reserved strictly for the wealthy, and it seems that’ll be the case in the future as well.

    • Great point on affordability of these vehicles. Given the supply constraints of batteries due to COVID and other world affairs, the casts haven’t decreased as anticipated (or hoped, rather). That is why EVs are still very much in need of federal and state incentives to increase adoption levels. Once those incentives are built up, customer demand will increase, signaling to the manufacturers that it is very much worth their time to invest in building better, more affordable EVs. Hopefully, this will open up manufacturing for these new vehicles locally, compounding the benefits!

      • Many of those BEVs come with a hefty dealer markup and/or are not available due to the supply chain issues. I’ve heard in some cases $10,000 to $20,000 for the Mustang and F150 Lightning.
        Another issue to note, when I leased a Kona EV three years ago they subtracted the $7500 tax credit from the base price for the lease. When I was looking into turning it in for an Ioniq 5 I found that Hyundai Finance is now pocketing the tax credit, essentially adding that to the total price when compared to a purchase.

        Hopefully there will be many more models available in sufficiency quantities over the next year or so.

  8. Good report. My only comment – Not everyone wants heat pumps implied in the post.. The reason is some residents will use the electric heating coils which lead to exorbitant utility bills. This happens when the heat pumps don’t extract enough “heat” to maintain a warm interior. This in turn causes exorbitant electric kwh usage which in turn causes very high electric utility bills for residential user on a limited budget. I was a Certified State Residential Auditor for several years. I audited thousands of residential homes. I observed this issue at residential homes in remote foothill regions. The residential customers burned firewood to stay warm and or installed propane heaters. (And shutoff or disconnect the electric resistance coils of the heat pump.

    • After I installed a Tesla Solar Glass Roof, I found that I had 5 megawatt hours of electricity left over from the summer months. Since I knew my solar system would still be producing in the winter, but less than I needed, I figured I would use 2 megawatt hours of those banked kilo watt hours from October through April when I would start over producing again. So, what to do with the 3-megawatt hours the utility at true-up would only give 3 cents for? I turned off my furnace pilot light and started using only resistance heating coil fan forced heaters to see how far I could get through the winter with only electric heat. Watching my smart meter and knowing what it read at my last true-up, I followed the reading back up, but it never reached the old true up reading and I stayed on electric heating the whole fall, winter and spring. I live in the San Francisco Bay area where winters are mild, so for our area, putting in enough solar can bank one’s home to use electric heating. I could not have done this if it were not for the low true up compensation given by PG&E and East Bay Community Energy. If East Bay Community Energy still gave the 10 cents per kilo watt hour at true-up, they used to give, I would have cashed in my $300.00 true-up for cash and purchased the natural Gas for my furnace. I have NEM-2.0 and get full value in my banked power that is re-used in the winter. Under the proposed NEM-3.0, the lower banked compensation would not have let me do the electric heat and would force me to use the gas furnace unless I could double my solar panel output with 16,000 additional watts of solar and no residential roofs, I know of, can produce 32,000 watts of solar to replace the natural Gas furnace, natural Gas hot water heater and charge up an electric vehicle and power the home, under NEM-3.0, to meet the California mandates being pushed onto homeowners or renters. Only by getting utility rates in California down from the current 38 cents per kilo watt hour to the national average of 13 cents per kilo watt hour will homeowners ever be able to afford to replace Natural Gas with Electrical heating, cooking, hot water, and EV charging. Can you imagine the air quality if everybody started use wood burning stoves and fireplace inserts?

    • Thanks for noting the technical limitations of heat pumps as the temperature drops.

      Last month we purchased a couple portable air conditions that are capable of providing heat down to am ambient temperature of 48F. We plan on using them in the winter to take the temperature up from the 55F or so that our fossil fuel based heating system(s) will be set at.

  9. Hybrids, even PHEVs, would be a no-brainier. I wonder what discussions took place when the ICE cars were introduced in large numbers? Need for roads, wouldn’t you think. And those cost a bit too, and took longer to build.

    But, seriously, the concept of micro grids has been making the rounds of the tech world for twenty plus years; that could be a short- term, perhaps even permanent solution.

    • Microgrids absolutely are a viable solution. A homeowner will only have to devote about 10% of their battery capacity to support home usage with good household power management software, and with the cost of an EV battery assigned to transportation costs, a independent MG becomes highly cost effective in comparison to current and future utility rates.

      • The poor, renters, mobile homes do not have solar and battery systems. The PG&E prices for electricity are outlandishly high compared to the rest of the country. Switching to renewables is a great idea in theory, but not when it costs 3 to 4 times as much as the rest of the world pays for electrical power in transmission and line costs here in California. PG&E collects billions of dollars for its long-distance transmission lines and micro grids, run by PG&E, would just add to their Big Utility” legacy costs to the compensation. Only by breaking up into smaller, local utilities and adding storage on the local level would we ever get electric utility rates back down to normal.

      • Richard McCann, I would be very interested to know what assumptions lead to your 10% conclusion. Certainly it would depend on the battery capacity and the load profile of the home that it serves?

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