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

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The challenge now: To make every day Earth Day.

YESTERDAY THINGS-TO-THINK-ABOUT WEDNESDAY, December 7:

  • TTTA Wednesday-ORIGINAL REPORTING: A Stakeholder-Driven Change In Thinking For Regulators
  • TTTA Wednesday-Linked Efficiency, Equity, Emissions Cutting Efforts Grow At The State Level
  • THE DAY BEFORE

  • Monday Study – California’s New Answer For Solar
  • THE DAY BEFORE THE DAY BEFORE

    THINGS-TO-THINK-ABOUT WEDNESDAY, November 30:

  • TTTA Wednesday-ORIGINAL REPORTING: New Power System Approaches To Customer-Owned Generation
  • TTTA Wednesday-New Tax Credits For New Energy
  • THE DAY BEFORE THAT

  • Monday Study – The West’s Market Opportunity
  • THE LAST DAY UP HERE

  • Weekend Video: Ocean Wind On The Verge
  • Weekend Video: Big Funding To Long Duration Storage
  • Weekend Video: The Mighty Missip’ Runs Down
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    Founding Editor Herman K. Trabish

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    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

    email: herman@NewEnergyNews.net

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

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  • FRIDAY WORLD, December 9:
  • Global Climate Goal Rises To 1.7 C
  • Exploring The Potential Of Green H2

    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)

    Abstract

    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.

    Introduction

    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)…

    Conclusions

    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…

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