NewEnergyNews: 08/01/2022 - 09/01/2022


Gleanings from the web and the world, condensed for convenience, illustrated for enlightenment, arranged for impact...

The challenge now: To make every day Earth Day.


  • Weekend Video: Dems’ Climate Bill On Verge
  • Weekend Video: Colbert Talks Transportation Electrification With DOE Sec
  • Weekend Video: Europe In Heat

  • FRIDAY WORLD HEADLINE-Consider Climate Endgame and Tipping Points –Scientists
  • FRIDAY WORLD HEADLINE-Global Energy Storage Boom Goes On


  • TTTA Wednesday-ORIGINAL REPORTING: Rate Design As A Solution
  • TTTA Wednesday-Jobs In Solar Rise With The Sun

  • Monday Study – A Close Look At The System Needed For Distributed New Energy

  • Weekend Video: Bill Maher Talks Population And Climate
  • Weekend Video: Build Back Better Comes Back With New Energy
  • Weekend Video: Pix Of The West Drying Out
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    Founding Editor Herman K. Trabish



    Some details about NewEnergyNews and the man behind the curtain: Herman K. Trabish, Agua Dulce, CA., Doctor with my hands, Writer with my head, Student of New Energy and Human Experience with my heart




      A tip of the NewEnergyNews cap to Phillip Garcia for crucial assistance in the design implementation of this site. Thanks, Phillip.


    Pay a visit to the HARRY BOYKOFF page at Basketball Reference, sponsored by NewEnergyNews and Oil In Their Blood.

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  • MONDAY’S STUDY AT NewEnergyNews, August 8:
  • Big Gains From Dems’ New Climate Bill

    Monday, August 08, 2022

    Monday Study – Big Gains From Dems’ New Climate Bill

    Preliminary Report: The Climate and Energy Impacts of the Inflation Reduction Act of 2022

    Jenkins, J.D., Mayfield, E.N., Farbes, J., Jones, R., Patankar, N., Xu, Q., Schivley, G., August 2022 (REPEAT Project/Princeton University)

    Preliminary Findings

    Historical and Modeled Net U.S. Greenhouse Gas Emissions (Including Land Carbon Sinks)

    The Senate Inflation Reduction Act would: • cut annual emissions in 2030 by an additional ~1 billion metric tons below current policy (including the Bipartisan Infrastructure Law) • close two-thirds of the remaining emissions gap between current policy and the nation’s 2030 climate target (50% below 2005) • get the U.S. to within ~0.5 billion tons of the 2030 climate target • reduce cumulative GHG emissions by about 6.3 billion tons over the next decade (through 2032).

    Annual Change in Net U.S. Greenhouse Gas Emissions Relative to Current Policy (including Bipartisan Infrastructure Law)

    The Inflation Reduction Act cuts U.S. emissions primarily by accelerating deployment of clean electricity and vehicles, reducing 2030 emissions ~360 Mt and ~280 Mt respectively. The Act also incentivizes installation of efficiency upgrades and carbon capture in industrial sectors, contributing ~130 Mt of reductions. Rebates, tax credits and grants to spur electrification and efficiency improvements in buildings; reductions in methane emissions in the oil and gas sector spurred by the methane fee and grants; and funding to improve conservation and carbon sequestration in forest and agricultural lands also contribute important reductions (~210 Mt collectively)

    Contributions to Additional Net U.S. Greenhouse Gas Emissions Reductions Below Current Policy Needed to Reach 2030 Climate Target

    percentage of net emissions reductions relative to Current Policy (including the Bipartisan Infrastructure Law) to reach 50% below 2005 levels (-1.5 Gt CO2e)

    The Inflation Reduction Act closes about two-thirds of the remaining emissions gap between current policy and the nation’s 2030 climate target (50% below 2005) By driving down the cost of clean energy and other climate solutions, the Act also makes it easier for states or cities or companies to increase their climate ambitions. It also reinforces the economic benefits of any future federal regulations. (These dynamic effects of the bill are not captured in this modeling.)

    Change in annual U.S. energy expenditures vs Current Policy (including Bipartisan Infrastructure Law)

    Enacting the Inflation Reduction Act would lower annual U.S. energy expenditures by at least 4% in 2030, a savings of nearly $50 billion dollars per year for households, businesses and industry. That translates into hundreds of dollars in annual energy cost savings for U.S. households.

    Tax credits, rebates, and federal investments in the Act would shift costs from energy bills to the progressive federal tax base, lower the cost of electric and zero emissions vehicles, heat pumps, and efficiency upgrades for individuals and businesses, and finance investments in energy productivity improvements and carbon capture equipment by industry.

    These savings do not include the additional downward pressure the Act will put on prices for oil and natural gas by driving lower consumption of these commodities, which will further reduce U.S. energy costs. Price responses to changes in demand are not captured in our energy system modeling.

    Using a spreadsheet model of oil and gas elasticities, REPEAT Project estimates that lower U.S. consumption of petroleum products and natural gas could reduce crude oil prices by approximately 5% and reduce U.S. natural gas prices by ~10-20% in the medium term (2030-2035)

    Historical Annual Capacity Additions vs. Modeled Annual Average Capacity Additions

    The Inflation Reduction Act could spur record-setting growth in wind and solar capacity, with annual additions increasing from 15 GW of wind and 10 GW of utility-scale solar PV in 2020 to an average of 39 GW/year of wind additions in 2025- 2026 (~2x the 2020 pace) and 49 GW/year of solar (~5x the 2020 pace), with solar growth rates increasing thereafter.

    The bill would also incentivize deployment of carbon capture at new and existing natural gas power plants and retrofits of existing coal plants, due to the enhanced 45Q tax credit.

    Several constraints that are difficult to model may limit these growth rates in practice, including the ability to site and permit projects at requisite pace and scale, expand electricity transmission and CO2 transport and storage to accommodate new generating capacity, and hire and train the expanded energy workforce to build these projects. Modeled results should thus be taken as indicative that IRA establishes strong financial incentives to build capacity at the modeled pace, while non-financial challenges may constrain the pace of real-world deployment relative to modeled results. Several policies in IRA and the Bipartisan Infrastructure Law, as well as proposed permitting reforms to be considered by Congress this Fall, can reduce these non-financial barriers (e.g. reforms to transmission siting and funding for CO2 transport & storage in IIJA; funding to expedite NEPA review in IRA; transmission investment funding in both bills).

    Annual capital investment in energy supply related infrastructure

    The Inflation Reduction Act would drive nearly $3.5 trillion in cumulative capital investment in new American energy supply infrastructure over the next decade (2023-2032).

    That includes more than $20 billion in annual investment in CO2 transport & storage and fossil power generation w/carbon capture by 2030.

    Annual investment in hydrogen production (including electrolysis and methane reforming w/carbon capture) increases to $3 billion annually by 2030, triple levels under current policy, and rises to over $50 billion by 2035.

    The Act has the greatest impact on investment in wind power and solar PV, which nearly doubles to $321 billion in 2030, versus $177 billion under current policy.

    The Act will drive substantial additional investments by households and businesses on the demand side of the energy system, including purchases of more efficient and electric vehicles, appliances, heating systems, and industrial process.

    It also provides tens of billions of dollars in grants, tax credits, and loan programs to develop manufacturing and supply chains for clean energy components, batteries, electric vehicles and critical minerals, spurring additional capital investment (and associated jobs) not captured in this report.

    Annual carbon dioxide captured for transport and geologic storage

    Incentives for carbon capture, storage, and use in the Inflation Reduction Act would build on demonstration funding in the Bipartisan Infrastructure Law to make carbon capture a viable economic option for the most heavily emitting industries, such as steel, cement, and refineries, as well as power generation from coal and natural gas.

    The total volume of CO2 captured for transport and geologic storage across energy and industry could reach 200 million tons per year by 2030, if sufficient investment in transport networks and storage basins can be deployed.1

    That includes roughly 110 million tons across industries and 90 million tons in power generation.2 Modeled results include 6 gigawatts of carbon capture retrofits at existing coal-fired power plants and 18 gigawatts of gas power plants with carbon capture installed by 2030.

    Modeled Net U.S. Greenhouse Gas Emissions (Including Land Carbon Sinks) Under High and Low Oil and Gas Production Scenarios

    Global and domestic demand for petroleum products and natural gas will be much larger drivers of future U.S. oil and gas production than the changes to public lands provisions in the Inflation Reduction Act.

    To address this uncertainty, REPEAT Project constructs high and low oil and gas production scenarios that span a wide range of potential future domestic production (the variation in 2030 equals 11-12% of 2021 production levels, see p. 15) and estimates the impact on U.S. emissions for each scenario.

    The low oil and gas production scenario assumes that reductions in U.S. petroleum products and natural gas consumption spurred by the Act result in lower domestic fossil fuel production while holding exports of oil and liquefied natural gas (LNG) fixed at the trajectory in the EIA’s Annual Energy Outlook 2022 (AEO 2022).

    The high oil and gas production scenario assumes declining domestic consumption increases U.S. fossil fuel exports, with domestic production of oil and gas equal to the levels in AEO2022.

    Despite wide variation in oil and gas production, the difference in 2030 U.S. emissions between high and low oil and gas production scenarios spans only 40 million metric tons per year; that’s a plus or minus 2 percent variation around the ~1 billion tons per year of emissions reductions driven by the bill in 2030 (see p. 6).

    The Inflation Reduction Act does include several notable changes to public lands policy that could affect oil and gas production in federal lands and waters.

    The Act specifically requires sale of four offshore lease areas that were previously withdrawn by court order or executive action. It also implements new rules that tie offshore wind lease offerings to recent offshore oil and gas lease offerings and links renewable energy leasing and right-of-way issuances on public lands to recent onshore oil and gas lease offerings.

    The Act simultaneously increases royalties and rental fees for fossil fuel production in federal lands and waters, which may put downward pressure on future production. The Act also establishes a new fee on methane emissions in the oil and gas supply chain and provides $1.55 billion in funding to assist companies in monitoring and reducing methane pollution.

    Modeling the specific impact of these countervailing provisions is challenging, but their impact is expected to be much smaller than the variation in production spanned by our high and low oil and gas production scenarios…

    Saturday, August 06, 2022

    Dems’ Climate Bill On Verge

    It could be the biggest U.S. funding for climate ever.From MSNBC via YouTube

    Colbert Talks Transportation Electrification With DOE Sec

    Colbert and Sec. Granholm talk about how the imperfect bill before Congress is worth passing to support the transition to clean transportation.From The Late Show with Stephen Colbert via YouTube

    Europe In Heat

    This is the summer the world woke up to the crisis.From ClimateAdam via YouTube

    Friday, August 05, 2022

    Consider Climate Endgame and Tipping Points –Scientists

    Climate endgame: risk of human extinction ‘dangerously underexplored’ – Scientists say there are ample reasons to suspect global heating could lead to catastrophe

    Damian Carrington, 1 August 2022 (UK Guardian)

    “…The risk of global societal collapse or human extinction has been ‘dangerously underexplored’, climate scientists have warned…[Though a ‘climate endgame’ has] a small chance of occurring, given the uncertainties in future emissions and the climate system, cataclysmic scenarios could not be ruled out, they said…Explorations in the 1980s of the nuclear winter that would follow a nuclear war spurred public concern and disarmament efforts, the researchers said.

    The analysis proposes a research agenda, including what they call the ‘four horsemen’ of the climate endgame: famine, extreme weather, war and disease…[It argues there are too] few quantitative estimates of the total impacts…A thorough risk assessment would consider how risks spread, interacted and amplified…Particularly concerning are tipping points, where a small rise in global temperature results in a big change in the climate, such as huge carbon emissions from an Amazon rainforest suffering major droughts and fires.

    Tipping points could trigger others in a cascade and some remained little studied…such as the abrupt loss of stratocumulus cloud decks that could cause an additional 8C of global warming…[A] climate breakdown could exacerbate or trigger other catastrophic risks, such as international wars or infectious disease pandemics, and worsen existing vulnerabilities such as poverty, crop failures and lack of water…[S]uperpowers may one day fight over geoengineering plans to reflect sunlight or the right to emit carbon…

    New modelling in the analysis shows that extreme heat – defined as an annual average temperature of more than 29C – could affect 2 billion people by 2070 if carbon emissions continue…The current trend of greenhouse gas emissions would cause a rise of 2.1-3.9C by 2100. But if existing pledges of action are fully implemented, the range would be 1.9-3C. Achieving all long-term targets set to date would mean 1.7-2.6C of warming…” click here for more

    Global Energy Storage Boom Goes On

    Global energy storage: staggering growth continues – despite bumps in the road; China continues to set the pace for energy storage market growth – while the US feels the lingering impact of the solar anticircumvention investigation

    Dan Shreve and Anna Darmani, 28 July 2022 (Wood Mackenzie)

    The global energy storage market is set to reach the precipice of the 500GW milestone by 2031 – with the US and China representing 75% of global demand in a highly consolidated market…The US is set to be a 27 GW annual market by 2031; 83% of that volume is grid-scale…[but there were] 2022 and 2023 demand downgrades of 34% and 27% resulting from an antidumping and countervailing duties (AD/CVD) tariff suit in Q2…

    …[An Executive Order (EO) issued on 6 June provided] a two-year delay of new duties on solar cells and modules imported from the countries named in the investigation – Cambodia, Malaysia, Thailand and Vietnam. Most projects are now expected to be delayed, rather than cancelled, and a near-term rebound is possible…[Europe’s energy storage market] is set to increase fivefold to 2031, [but] mid-term growth could stall if policies fail to improve the economics…Europe’s demand lags behind that of China and the US, the energy storage superpowers, as its grid-scale storage market has yet to find its footing. The distributed storage segment continues to dominate – but dramatic renewable supply growth, gas supply tightness and overburdened interconnectors can kickstart the region’s grid-scale market in the next decade…

    China leads the Asia Pacific energy storage market, and is a pace-setter for global growth. However, the profitability of storage projects in the region remains a challenge…China’s Fourteenth Five-Year New Energy Storage Development Implementation Plan – released in March 2022 – reiterated the central importance of energy storage…[and] proposes that by 2025 energy storage will enter the large-scale development stage, with system costs falling by more than 30% through improved technology performance…” click here for more

    Wednesday, August 03, 2022

    ORIGINAL REPORTING: Rate Design As A Solution

    2022 Outlook: A new recognition is coming of rate design's critical role in the energy transition; New rate design price signals target reducing customer bills and easing system peak demand.

    Herman K. Trabish, January 19, 2022 (Utility Dive)

    Editor’s note: This story is an object lesson for all those who think they know what is coming. Most of the big changes predicted in this piece have been waylaid by the unexpected impacts of the Ukraine war and its attendant inflation, supply chain shortages, and the energy crisis it is brought to Europe.

    New regulations and legislation in 2022 will continue seeking rate designs with price signals that shift customer electricity usage to more effectively benefit both customers and the power system, utility and other analysts said.

    The growing roles of variable generation in the power supply and distributed energy resources (DER) in meeting demand make effective price signals to customers critical, the analysts agreed. The emerging consensus is toward rates with signals that will reduce costly system demand peaks and lower customer bills, recognize the value of DER in doing that, and increase access to new technologies and cost savings.

    Utility and regulatory leaders have realized new power system dynamics require “prices to be smarter,” Brattle Group Principal Sanem Sergici said. They are increasingly aware that effective price signals to customers are necessary “for utilities serious about load flexibility, decarbonization, electrification and reliability.”

    Similar new multi-part rate designs approved in last year’s settlements with clean energy advocates for Duke Energy in North and South Carolina typify that realization. “The power system is changing dramatically, but traditional rate design is limited to balancing historic and future cost recovery,” Duke Energy Vice President, Rate Design and Strategic Solutions, Lon Huber said. “These new designs resolve that tension by addressing system cost to serve but offering dynamic incentives for emerging technologies that meet future system needs like peak demand or reliability.”

    Beyond policy work on rate design objectives, there are new rate design implementations, and they are leading to better insights into the value of price signals for utilities and customers, the utility and independent analysts said. Many of the resulting new proposals about rate design may shape DER and smart technology uses toward a cleaner, more affordable, more reliable power system, the analysts added.

    Beyond routine rate cases, there were over 150 rate design policy initiatives in 2021 addressing new time-of-use (TOU) or time-varying rate (TVR) structures, or DER and electric vehicle charging, according to Autumn Proudlove, North Carolina Clean Energy Technology Center (NCCETC) senior policy program director. Innovative rate designs are part of policymakers’ efforts to keep up with technology as the U.S. power system transitions into “an interconnected web” of DER-owning customers, NCCETC’s Q3 2021 grid modernization policy update said.

    “TOU rate designs are being developed that give customers price signals to adopt new technologies that serve changing system demand,” Proudlove said. The rate designs may also include an incentive, like a rebate for a new technology, that saves the utility “more than the cost of the rebate” if the customer makes the investment, she added. Managing electric vehicle charging with TOU rates that encourage off-peak charging is an emerging national trend, she added. Some states, like Hawaii and Minnesota, have proposed three-part TOU designs with on-peak and off-peak periods and a super off-peak very low rate after midnight, or a very high critical peak rate for charging during reliability challenges… click here for more

    Jobs In Solar Rise With The Sun

    Solar Jobs Up in 47 States, Increase 9% Nationwide in 2021

    July 26, 2022 (Interstate Renewable Energy Council)

    “Solar energy jobs were up in 47 states and increased 9 percent nationwide from 2020 to 2021 to a total of 255,037 solar workers…[according to the annual National Solar Jobs Census. In] a year of record solar installations driven by increased demand for renewable energy among residential customers, municipalities, businesses, and electric utilities…the solar industry added 21,563 jobs in 2021, with more than two-thirds of these new jobs (14,350) at installation and project development firms…

    Over the past decade, U.S. solar employment has more than doubled from 105,145 jobs in 2011 to 255,037 jobs in 2021…[California, with 75,712 jobs] continues to lead…followed by Florida (11,761 jobs), Massachusetts (10,548 jobs), New York (10,524 jobs), and Texas (10,346 jobs)…California also led for the number of jobs added in 2021 (7,035 new jobs), followed by Massachusetts (+1,053 jobs), Nevada (+1,019 jobs), and Arizona (+932 jobs)…The solar industry still has more work to do to meet its goals for diversity, equity, and inclusion and extend the benefits of the clean energy economy to underrepresented groups…

    …[W] omen made up just under 30 percent of the solar workforce in 2021, while Black employees made up 8 percent of the workforce, Latino or Hispanic workers made up 20 percent, and Asian workers made up 9 percent. Fewer than one-third of solar firms reported strategies to increase female, ethnic or racial minority, or LGBTQ+ hires…The solar industry can offer a path to advancement and a family-sustaining career, including for those without a two- or four-year college degree…” click here for more

    Monday, August 01, 2022

    Monday Study – A Close Look At The System Needed For Distributed New Energy

    Can Distribution Grid Infrastructure Accommodate Residential Electrification and Electric Vehicle Adoption in Northern California?

    Anna Brockway, Duncan Callaway, and Salma Elmallah, June 2022 (University of California, Berkeley, Energy Institute at Haas)


    In this paper we ask: in what ways will utilities need to upgrade the electric distribution grid to accommodate electrified loads, and what will those upgrades cost? Our study focuses on the PG&E service area in Northern California, which serves 4.8 million electricity customers and is subject to aggressive targets for both EV adoption and electrification of residential space and water heating. We create spatio-temporally detailed electricity demand forecasts, and compare that demand to distribution infrastructure limits across a range of technology adoption scenarios. We find that electrification of residential space and water heating will lead to fewer impacts on distribution feeder capacity than EV charging, but that both transitions will require an acceleration of the current pace of upgrades. We also find that timing and location have a strong influence on total capacity additions in important ways: For example, scenarios that favor daytime EV charging have similar impacts to those with managed nighttime residential charging, but uncontrolled nighttime residential charging could have significantly larger impacts. We project that these upgrades will add at least $1 billion and potentially over $10 billion to PG&E’s rate base. We conclude that measures that enable the completion of a high number of upcoming upgrade projects – including addressing workforce and supply chain constraints, and pursuing nonwires alternatives like energy storage and demand response – are critical to successful electrification.


    Transitioning from direct fossil fuel combustion to using electricity to meet energy needs is a pillar of many climate change mitigation strategies. Two of those energy needs, residential space and water heating and light-duty vehicles, make up about 10% and 20% of greenhouse gas (GHG) emissions from the U.S. energy sector, respectively (EIA 2022a; EIA 2022b; Appendix A). In California, passenger vehicles contributed 28.5% of the state’s emissions in 2019 (CARB 2021a). A recent nation-wide assessment showed that meeting climate goals would be impossible without investment in residential heating electrification as well electric vehicle (EV) adoption (NASEM 2021).

    Both residential electrification (replacing gas-burning appliances with electric space and water heating appliances) and electric vehicle adoption necessitate multiple infrastructure transitions. These transitions include preparing electric infrastructure for increased demand while phasing out gas infrastructure and combustion engine vehicles, and are shaped by workforce transition and supply chain dynamics; concerns about financing, affordability and access to technologies; and questions of how quickly infrastructure can be deployed (Levinson and West 2018; Metais et al. 2022; Egbue, Long, and Samaranayake 2017; Bauer, Hsu, and Lutsey 2021; Das et al. 2020; Emerald Cities Collaborative 2020; Greenlining Institute 2019; Building Decarbonization Coalition 2019; Aas et al. 2020; National Renewable Energy Lab 2021).

    Because electrification may is likely to change the timing or geography of electricity use, its impact on the electricity grid is particularly important to understand. As Figure 1 shows, the electricity grid can be partitioned into generation, transmission and distribution components. Electrification has implications for each: for instance, investments in electricity generation and the expansion of long-distance transmission infrastructure will be needed to serve new loads (Waite and Modi 2020; National Renewable Energy Lab 2021). The distribution grid—i.e. the periphery of the grid located closest to customers—has received less attention than generation and transmission, in part due to the difficulty of capturing the uniqueness of each individual circuit (Murphy et al. 2021, p. 25). In this paper, we take a spatially and temporally resolved approach to understanding how residential electrification and EV adoption might impact the distribution grid. Our spatial units of analysis are substations and distribution feeders, which are electric circuits that extend from a distribution substation and deliver electricity to end users. One feeder is composed of multiple line segments, and includes the conductors themselves along with equipment such as transformers, voltage regulators, and monitoring devices (PG&E 2017).

    Specifically, we address the following question: in what ways will utilities need to upgrade the electric distribution grid to accommodate electrified loads, and what will those upgrades cost? We focus our study on light-duty transportation and residential electrification in the Pacific Gas & Electric (PG&E) service area in Northern California. We choose PG&E both because California has aggressive decarbonization goals and policies to support electrification, and because rich data on PG&E’s distribution infrastructure are available. We use these data, which include a range of spatiotemporally explicit characterizations of energy consumption and distribution system capacity, to assess the extent to which distribution grid infrastructure within PG&E’s utility territory can serve projected electricity needs. We provide a spatially- and temporally-explicit and system-specific analysis of the potential changes in electricity usage in PG&E’s utility territory due to electrification. We compare these load shape changes to available distribution grid capacity. Where that capacity falls short of the estimated need, we report the amount by which distribution infrastructure needs to be expanded, including the potential cost of those expansions and the number of distinct upgrade projects that will need to be performed.

    Our key conclusions are as follows.

    …First, we project that the number of distribution grid upgrades may pose a bottleneck to electrification goals, necessitating workforce expansion or investment in non-wires alternatives like demand response and storage to reduce the required volume of infrastructure upgrade projects.

    …Second, we find that EV charging scenarios that favor daytime charging have comparable distribution grid impacts to nighttime charging scenarios; considering California’s high solar production and correspondingly low daytime electricity prices, policies that favor workplace charging may have significant benefits over those that favor nighttime residential charging.

    …Finally, we project that the total cost of these upgrades will at least $1 billion and potentially over $10 billion. These costs need to be taken into consideration along with expected demand growth, within detailed rate base calculations, and in concert with appliance upgrade costs to fully understand their ultimate impacts on annual ratepayer expenditures.

    In what follows, we review the scholarship on grid upgrades related to electrification (Section 1.1), discuss the policy context in our study area (Section 1.2), describe our data and modeling approach (Section 2), present and discuss the results (Section 3), and conclude by discussing the implications of our results for electrification transitions in Northern California (Section 4).

    1.1. Residential electrification, EV adoption, and the distribution grid

    There is a growing body of work characterizing grid-related impacts from electrification, including impacts on grid operations (Blonsky et al. 2019; Sahoo, Mistry, and Baker 2019), interconnection practices and standards (Das et al. 2020), and power generation and transmission (Murphy et al. 2021; Waite and Modi 2020). However, existing studies on electrification-driven distribution grid upgrade needs are generally spatially and temporally coarse. For example, studies of impacts in California project that residential electrification may shift peak demand from the summer to the winter (Hopkins et al. 2018; Mahone et al. 2019), potentially leading to fuller utilization of California’s electric distribution grid infrastructure year-round (Mahone et al. 2019). Yet these analyses do not estimate the specific type and magnitude of upgrades needed.

    Because home heating and EV charging will create demands for electricity that vary spatially and temporally, estimating distribution grid impacts due to electrification requires spatially and temporally explicit models of electricity consumption. The characteristics of distribution grid infrastructure also vary spatially: research on distribution grid substations (Allen et al. 2016; Burillo et al. 2018; Sathaye et al. 2011) and circuits (Brockway, Conde, and Callaway 2021) has identified correlations with geography and demographics, including the vulnerability of substations to climate change (Burillo et al. 2018) and the ability of distribution circuits to accommodate distributed energy resources (Brockway, Conde, and Callaway 2021). Investigating the distribution grid impacts of electrification in a spatially and temporally coarse manner, then, is insufficient given the importance of the timing and location of new electric loads as well as the timing and location of the distribution grid’s ability to serve them.

    We are aware of two studies…

    1.2. Electrification in Northern California

    Our study is based in the PG&E service area in Northern California. PG&E is a combined natural gas and electricity investor-owned utility (IOU) in Northern California, with over 4 million natural gas and electricity customer accounts (Pacific Gas & Electric 2015). In the past ten years in PG&E, electric heating penetration has nearly doubled in cooler, coastal regions (Kema, Inc. 2010; DNV GL 2020) and residential electrification has expanded throughout the service area. California also leads the nation in EV adoption (Alternative Fuels Data Center 2021): EVs constituted over 11% of light-duty vehicle sales in 2021 (California Energy Commission 2021), and PG&E estimates that one in five EVs in the U.S. charge from its grid (PG&E 2021b).

    The market share of these technologies is poised to grow further due to ongoing investments and regulations. To date, building electrification has been pursued through incentives, building code amendments (CARB 2021b), and municipal gas phaseouts (Gough 2021); state-level investment in building electrification is expected to total $1 billion over the next two years (Velez and Borgeson 2022). EV adoption has been pursued through ambitious targets: in 2018, the state established a goal of 5 million zero-emission vehicles by 2030 (California Legislature 2018; Office of Governor Edmund G. Brown Jr. 2018), and executive order N-79-20 increased the goal to 100 percent of in-state sales by 2035 (Office of Governor Gavin Newsom 2020), for an anticipated total of approximately 8 million EVs in 2030 (Alexander et al. 2021).

    Northern California’s shifting regulatory and planning context also provides an opportunity to investigate the distribution grid impacts of electrification. While a lack of data has posed a barrier to detailed analyses of the distribution grid, IOUs in California are now required to provide detailed, publicly-available data on distribution infrastructure, including the ability of distribution lines and substations to accommodate new loads, in their ICA maps (CPUC 2021c; CPUC 2022; Cooke, Schwartz, and Homer 2018)…


    Residential electrification and EV adoption, both necessary measures for climate change mitigation, require additional electricity usage. This electricity demand will vary spatially and temporally, but it will also vary based on technology adoption rates, equipment efficiencies, and EV charging patterns. Many aspects of infrastructure planning need to adapt to electrification; among them is distribution grid planning.

    This paper evaluates how distribution infrastructure planning need to change by constructing load shapes for electrified residential heating and EV charging using a combination of bottom-up modeling and existing projections. We combined these load shapes with data on PG&E’s distribution circuit and substation load integration capacity limits to quantify where and when residential heating electrification and EV charging might exceed infrastructure limits, prompting upgrades. We calculated the potential cost of upgrades using existing cost data from PG&E, and compared the projected rate of upgrades to current upgrade practices. We determined upgrade needs and costs for the years 2030, 2040, and 2050, and observed differences in results based on EV and residential electrification adoption timelines, EV charging scenarios, and cost estimates.

    Our analysis leads to six key conclusions. First, relative to EVs, residential electrification leads to far fewer impacts on distribution feeder capacity and needs for upgrade projects, even in our highest penetration scenario.

    …Second, the timing of EV charging can reduce the GW upgrade requirements for distribution feeders: workplace charging and smart residential charging lead to lower GW upgrade requirements than a residential charging scenario in which many EVs begin charging at midnight.

    …Third, our analysis projects that the number of feeder and substation upgrade projects needed to meet aggressive electrification goals could exceed PG&E’s current rate of upgrades, especially in the next decade. Distribution grid upgrades, then, may pose a bottleneck to electrification goals, necessitating workforce expansion or investment in non-wires alternatives like demand response and storage to reduce the required volume of infrastructure upgrade projects.

    …Fourth, in contrast to the upgrade need in GW, the choice of EV charging scenario—even those with demand response—have little impact on the projected number of upgrade projects.

    …Fifth, the projected upgrade needs are spatially heterogeneous; we find that they are more concentrated in counties in the San Francisco Bay Area and in parts of the Central Valley, including Fresno County.

    …Sixth, and finally, we project that the total cost of these upgrades will be at least $1 billion and potentially more than $10 billion. These costs need to be taken into consideration with expected demand growth, within detailed rate base calculations, and in concert with appliance upgrade costs to fully understand their ultimate impacts on annual ratepayer expenditures.

    Our modeling approach is subject to some limitations and opportunities for future analysis, as discussed in detail in Section 3.4. In particular, when we capture known sources of uncertainty in distribution system capacity and upgrade costs, the range of potential future impacts is substantial, and new modeling processes need to identify ways to reduce this uncertainty. Another critical opportunity for future analysis is to consider the value of feeder-specific demand response, storage and distributed energy resources. These types of measures could be deployed quickly and in a modular way and could significantly offset the distribution capacity expansion work and costs projected in this study.

    …Our results prompt several recommendations for practices and policies to support future electrification.

    …First, utilities can reduce the uncertainty of future capacity upgrade needs by updating their load integration modeling processes to capture plausible scenarios for electrification along distribution circuits, as well as likely mitigation strategies (such as low cost switching operations versus higher cost infrastructure upgrades).

    …Second, our results align with policies that support workplace EV charging, because we find that workplace EV charging has some of the smallest distribution circuit impacts, and because this charging occurs during periods of the day when wholesale electricity prices are typically low.

    Finally, our findings are relevant to ongoing discussions on resourcing, labor, and pricing in the electric utility sector. Distribution grid infrastructure is subject to pre-existing trends of lack of equipment availability and a shrinking workforce that could contribute to bottlenecks in electrification, particularly considering that we find that many circuit upgrade needs are relatively near-term. Our results suggest that programming and research on measures that can ease these bottlenecks, including workforce training, is essential to facilitate electrification…