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The impact of wildfires and beneficial electrification on electricity rates in PG&E’s service territory
The Electricity Journal 33 (2020) 106710
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The Electricity Journal journal homepage: www.elsevier.com/locate/tej
The impact of wildfires and beneficial electrification on electricity rates in PG&E’s service territory
T
Catherine Hay, Mohit Chhabra (M.S.)* Natural Resources Defense Council San Francisco, CA, United States
ARTICLE INFO
ABSTRACT
Keywords: Electric Rates Wildfires Electrification
Building and transport electrification, an essential strategy to California’s carbon reduction goals, requires affordable electricity for customer adoption. We estimate the costs borne by the electric sector for its involvement in the 2017 and 2018 wildfires in Northern California to be significant and cause residential electric rates in PG& E territory to increase from 23 cents/kWh (2018) to 42 cents/kWh (2030). This rate increase could be limited to 35 cents/kWh through proactive transportation and building electrification.
1. Introduction 1.1. Background on the problem Buildings and transportation are a major source of greenhouse gas emissions (GHG) in California, responsible for over 60 % of GHG emissions in the state (California Energy Commission, 2018). To comply with the state’s carbon reduction goals of 40 % reduction below 1990 levels, and carbon neutrality, large scale electrification of transportation and buildings are required.1 A recent state-sponsored study estimates that the lowest-cost and most plausible pathway for the state to achieve carbon neutrality by 2045 requires electrification of energy services, especially the transportation and building sectors (Bedsworth et al., 2018). The viability of switching to electricity as a heating and transportation fuel depends in part on keeping the price of electricity affordable for Californians in absolute terms and relative to future gasoline and natural gas prices. Electricity prices in California have been rising steadily since 2000 and the recent catastrophic wildfires will put further upward pressure on electric rates (California Public Utilities Commission (CPUC), 2019a). Although electric rates in California have traditionally been higher than average rates in the United States,
electric bills in California have been lower because of lower energy usage in the state. However, as wildfires continue to occur in the state with increasing magnitude and frequency, uncertainty remains on how much utilities will bear the costs of fires, it is important to understand the impact recent state legislation in response to wildfires has had on electric rates (Westerling, 2018). In this paper, we estimate (1) the impact of the 2017 Northern California wildfires and Camp Wildfire on average residential electric rates2, (2) the extent to which an increase in these electric rates can be counteracted through transportation and building electrification and (3) the resultant impact of these forecasted rates on customer-economics of switching to electricity as a heating and transportation fuel. 1.2. Background on electric rates and utility revenue requirement The average electric rate for a customer class can be estimated by dividing the utility’s total revenue requirement for each customer class by the electric consumption of that customer class.3 The total revenue requirement in California is defined as the amount of revenue a utility is allowed to earn by regulatory agencies to be able to provide reliable service to customers and earn a fair rate of return for shareholders on utility investments.
Abbreviations: AB, Assembly Bill; CCAs, community choice aggregators; CEC, California energy commission; CPI, consumer price index; CPUC, California public utility commission; ERRA, energy resource recovery account; EV, electric vehicles; FERC, federal energy regulatory commission; ICE, internal combustion engine; IOU, investor owned utility; GRC, general rate case; GWh, gigawatt-hour; kWh, kilowatt-hour; PG&E, Pacific Gas and Electric; PPAs, power purchase agreements; PPPs, public purpose programs; ROR, rate of return; SAR, system average rate; SB, Senate Bill; YOY, year-over-year ⁎ Corresponding author. E-mail address: [email protected] (M. Chhabra). 1 Assembly Bill (AB) 32, Senate Bill (SB) 100, and the governor’s Executive Order meet state-wide emission targets. 2 This impact is based on the costs pertaining to these wildfires that we know are to be borne by the electric sector at the time of writing this paper. 3 This simplified calculation does not consider sub-categories within each customer class. This is aligned with the intent of the paper: to understand the on-average impact of state policies on average residential electric rates in PG&E service territory. https://doi.org/10.1016/j.tej.2020.106710
1040-6190/ © 2020 Elsevier Inc. All rights reserved.
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The total revenue requirement for an investor owned electric utility in California is determined through many different proceedings at the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC).4,5 Given this complex process for estimating the total revenue requirements for utilities, there are a variety of methods that can be used to decompose and better understand the constituent elements of a utilities total revenue requirement. Fig. 1 illustrates three different ways to decompose Pacific Gas and Electric’s (PG&E) revenue requirement.
• By utility service type: PG&E’s revenue requirement can be broken
•
•
down into the following categories of service provided by the utility: generation (50 %), distribution (30 %), transmission (10 %), public purpose programs (PPPs) (6 %), bonds and fees (4 %), and nuclear decommissioning (< 1 %) (California Public Utilities Commission (CPUC) Energy Division, 2019). By type of payment to the utility: we subcategorize payments made to the utilities as either payments to recuperate operating expenses (e.g. operations and maintenance, cost of purchasing electricity), or payments to earn a rate of return on capital investments made by the utility.6 Operating expenses are equal to the sum of the costs realized to operate the electric grid, purchase power, and maintain business operations for the utility’s customers. A utility can recover its operating expenses annually.7 In this analysis, we apply this method to forecast PG&E’s revenue requirement because it best allows us to assign costs associated with wildfires to their appropriate category. We further explain this process in Section 3.1. California Public Utilities Commission (CPUC), 2019b By proceeding: Here we break out the revenue requirement based on which proceeding these revenue requirements are litigated and determined.
Fig. 1. PG&E 2018 Revenue Requirement Decomposition (California Public Utilities Commission (CPUC) Energy Division 2019).
customer in PG&E’s service territory and are thus agnostic to which load serving entity (LSE) serves the customer. Moreover, the results of this analysis are meant to represent the order of magnitude of change in electric rates expected from the phenomena studied for the average residential customer (as opposed to a precise forecast of electric rates). 2.2. Future scenarios modeled In order to understand the impact of the wildfires on electric rates and future impact of transportation and building electrification, we developed three different future-scenarios. 2.2.1. Counterfactual (“No-Wildfire”) scenario A scenario that excludes the impact of 2017 Northern California and 2018 Camp wildfires and the impact of the related legislation forms the basis of this analysis. This Counterfactual, No-Wildfire scenario allowed us to extrapolate utility expenses without the confounding impact of recent wildfires. We then were able to layer-in the individual impact of each incremental impact we intend to study.
PG&E’s total revenue requirement is split among each customer class (e.g. residential, commercial, industrial, and agricultural) based on relative cost of serving each customer class (California Public Utilities Commission 2019) and between revenue requirement for electricity services and natural gas services to determine electric rates for each customer class.
2.2.2. Base scenario The base scenario layers-in the impact of existing wildfire legislation on electric rates. Wildfire legislation: SB 901 (2018, Dodd) requires IOUs to prepare wildfire mitigation plans (WMP) to be approved by the CPUC. AB 1054 (2019, Holden) requires utilities to conduct safety upgrades worth $5 billion and establishes a $21 billion “safety fund” to be able to pay any claims that may arise from future possible wildfires. We modeled PG& E’s portion of the spending associated with these $5 billion safety upgrades by estimating that PG&E will approximately spend an additional $3.2 billion on wildfire safety investment. The safety fund will be created by extending an existing bond charge, approximately 0.5 cents per kWh, and is modeled as such.
2. Analysis context and methodology 2.1. Analysis results illustrate the impact on average residential customer rates in PG&E transmission and distribution territory Electric customers within PG&E’s transmission and distribution area are served electricity by multiple community choice aggregators (CCA) in addition to PG&E. Wildfire costs, as they pertain to the transmission and distribution infrastructure, will be borne by all customers in PG&E service territory independent of customer class, and independent of who purchases the electricity on behalf of the customer (PG&E or a CCA). Our analysis and results are applicable to an average residential
2.2.3. High electrification scenario The high electrification scenario builds off the base scenario by adding-in the rate impact of increased levels of building and transportation electrification necessary to meet California’s economy wide carbon reduction goals. The details of this step are further explained in the Appendix to this paper. In addition to higher levels of electrification, this scenario also modeled rate impacts of SB100. SB100 requires retail electricity to be carbon free by 2045. This will result in additional procurement of renewable contracts by utilities
4 General Rate Case (GRC), Energy Resource Recovery Account (ERRA), Transmission Owner (TO) rate case, specific program area proceedings such as a proceeding specific to energy efficiency. 5 The FERC oversees revenue related to transmission costs through a Transmission Owner rate case proceeding. 6 Utility owned assets and capital are collectively referred to as the utility rate base, and the earnings from these investments are referred to as the utility’s return on rate base. This paper applies simplified calculations to determine utility earnings that does not take into account or separate greenhouse gas emission credits and other smaller revenue requirement elements such as taxes as their effects on our analysis are likely small. 7 More tree trimming will increase operating expenses whereas new grid infrastructure will increase rate base that the utility earns a rate of return on (approximately 7%).
3. Methodology Details of the methodology applied to forecast electric rates for each scenario is presented in the Appendix to this paper. This section presents a summary of this methodology. The first step is to forecast PG&E’s total revenue requirements, the 2
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Fig. 2. Electricity Rates Through 2030 by Scenario Type.
Fig. 3. Annual EV and ICE Fuel Consumption in PG&E Service Territory for Each Scenario Modeled.
driving force behind the overall level of utility rates (California Public Utilities Commission 2017), by studying past trends in PG&E’s operating expenses, PG&E’s spending on expanding its capital investments or “rate base”, and the rate of return received by PG&E on its rate base capital investments. Future total revenue requirements are estimated using Eq. (1).
TRR = OE + r × (RB )
2030 are expected to increase from $1,933 to $2,469 because of increased utility spending as a result of the recent wildfires. Transportation and building electrification in line with California’s economy wide decarbonization goals limits this bill increase to $2,132 in 2030 thereby savings consumers $337 in 2030. These changes in future electric rates also impact consumer economics on adopting electric cars and water heaters as discussed in the following section.
(1)
Where: TRR = total revenue requirement ($) OE = operating expenses ($) r = rate of return on rate base (%) RB = rate base ($) This total revenue requirement is then separated into its gas and electric utility components using historical data (California Public Utilities Commission (CPUC) Energy Division, 2019). Once the total electric revenue requirement is determined, the average residential for each year is calculated in the following manner per Eq. (2) :
TRR e × p = ARR e S × s
4.2. End-use electrification Using the electric rates developed for each of the three scenarios, we compare the cost of switching fuel both from internal combustion engine (ICE) vehicles to electric vehicles (IC) as well as from gas water heaters to electric water heaters. 4.2.1. Transportation In our transportation comparison, we assume that both vehicles will drive 10,000 miles annually. The conventional gasoline vehicle will have a fuel efficiency of 25 miles per gallon, while the electric vehicle will drive 3.3 miles per kWh (Table 5). We use gasoline price forecasts from the CEC 2017 IEPR report for California (California Energy Commission (CEC) staff 2017). Electric vehicles in all three scenarios are more cost-effective than conventional gasoline vehicles in terms of fuel cost (see Fig. 3).8 EV drivers save between $750-$1000 annually from 2018 to 2030 on fuel. Cumulatively, this translates to EV drivers saving over $10,000 on fuel costs. On average, EV drivers save $54 more per year in the high electrification scenario compared to the base case. Thus, high levels of electrification will lead to customers adopting more electric vehicles due to the decrease in electric rates as a result of electrification.
(2)
Where: TRR e = total electric revenue requirement ($) for a given year p = residential revenues as % of total revenue (%) calculated using historic data S = total sales (kWh) forecasted for that same year s = residential sales as % of total sales (%) ARR e = average residential electric rate ($/kWh) for that year 4. Results and discussion 4.1. Electric rates by scenario This paper estimates average residential electric rates for all three scenarios considered in this analysis for each year through 2030. The results of our analysis, presented in Fig. 2, can be summarized as:
4.2.2. Water heaters Annual water heater operation costs to serve an average single-family home in PG&E service territory were calculated using electric rates derived under each and with the cost of operating a natural gas water heater.9,10 In the High Electrification scenario, switching from a natural
• In the Counterfactual scenario, which forecasts what the electric • •
rates would be if the 2017 and 2018 wildfires had not occurred, we estimate that average residential electric rates would increase from 23 cents/kWh in 2018 to 32 cents/kWh in 2030. In the Base scenario the electric rates increase from 23 cents/kWh in 2018 to 41 cents/kWh in 2030. This additional increase in electric rates is due to increased utility spending in response to the 2017 and 2018 wildfires as required by California legislature via SB901 and AB1054. This increase in electric rates can be curtailed to 35 cents/kWh in 2030 through aggressive electrification. Electrification puts downward pressure on electric rates by increasing the total amount of energy sales that fixed utility costs are spread.
8 To calculate electricity cost for EVs, this paper applies the average residential electric rate for each of the three scenarios studied. 9 We assume the input energy for the new gas heater is 131.8 therms and input energy for new electric heater is 742.5 kWh. Heat pump water heater consumption data are from study conducted by Ecotope for NRDC. Ecotope applied on-site HPWH performance data to develop calibrated models of HPWH performance for NRDC. We’ve used consumption data for the GE GeoSpring (2014) 50 gallons model. We then calculated an consumption for an equivalent gas water heater using energy factor data and simple engineering equations. 10 To calculate these energy inputs, we found the weighted average of base consumption for PG&E’s single-family population by climate zone of the GE 2014 Heat Pump Water Heater – medium cost and for a small gas storage water heater (0.60 EF – 0.639 EF). We used E3’s residential rate estimates for the high building electrification to estimate future natural gas residential rates.
For an average California residential customer, who consumes an average of 500 kW h per month, this means that annual electric bills in 3
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use electrification incentivize further electrification by keeping electric rates low. Thus, the adverse effects of an increase in electric rates due to the 2017 and 2018 wildfires can be somewhat mitigated via electrifying water heating and transportation. 5. Conclusion Wildfires and subsequent legislation will have a significant upward impact on average residential rates in PG&E’s service territory. Our analysis estimates that PG&E service territory’s average electric rates will increase from approximately 23 cents/kwh to more than 41 cents/ kWh in 2030 due in part to increased utility spending in response to recent wildfires in Northern California. Thus, making electricity less affordable compared to alternatives such as natural gas and gasoline.
Fig. 4. Annual Residential Water Heater Operating Cost for a Single-Family Home in PG&E Service Territory. Table 1 Building and transportation electrification demand assumptions.
Building Electrification (GWh) Transport Electrification (GWh)
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
– 366
– 415
– 469
– 605
– 756
– 1,040
59 1,196
141 1,513
265 1,498
431 1,528
627 1,708
844 2,019
Table 2 Operating expenses assumptions for three scenarios. Historical data pulled from PG&E 10-K reports (PG&E Corporation, 2018). YOY % change
Counterfactual
Base
High Electrification
Cost of Electricity O&M D&A
0.0 % 0.0 % 1.0 % 2.9 % Assumed to be 8 % of total rate base in all scenarios.
0.75 % 2.9 %
Table 3 Cost of capital and capital structure assumptions (PG&E Corporation, 2018). Cost Return on Equity 10.25 % (ROE Preferred Stock 5.60 % (RPE) Long-Term Debt 4.89 % (COD) Weighted Average Cost of Capital/ Rate of Return on Rate Base (r)
Capital Structure
Weighted Cost
52.00 % (E) 1.00 % (PE) 47.00 % (D)
5.33 0.06 2.30 7.69
% % % %
Table 4 Rate base annual growth rate assumptions for the different scenarios.
Rate base, YOY % change
Counterfactual
Base
High Electrification
4.47 %
5.81 %
5.81 %
Table 5 Transportation fuel cost comparison assumptions (Sivak and Schoettle 2018).
Total Miles Driven ICE Miles per gallon (mpg) EV Average Miles/kWh
Conventional
EV
10,000 25 –
10,000 – 3.3
Electrifying natural gas (space and water heating) and gasoline powered end uses (internal combustion engine cars) is critical to achieving California’s carbon reduction targets; both of which require lower electricity rates as compared to that of natural gas and gasoline. However, electrifying building natural gas-powered end-uses and gasoline powered transportation has the potential to mitigate some of this increase in electric rates by distributing utility costs over a larger sales base. Electrification, of the scale necessary to meet California’s carbon reduction goals through 2030, will have the impact of
gas water heater to a heat pump water heater saves the customer an average of $83 a year from 2019 through 2030. In the Base scenario, this annual average savings reduces to $69 per year. Fig. 4 presents the annual operating costs of water heaters in each scenario. Assuming a fifteen-year life of an average heat pump water heater, customers will save an additional $210 over the life of the water heater in operational costs when switching from a natural gas water heater to a heat pump water heater under a high electrification scenario. These additional customer savings again underscores the finding that high levels of end4
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constraining average PG&E residential electric rates to approximately 35 cents/ kWh in 2030. Electrification is thus a strategy not only to meet California’s carbon reduction goals but also to keep electricity affordable for Californians. Thus, forming a virtuous cycle, whereby increased levels of electrification makes further electrification a more economic prospect for future adopters. This study estimates that in 2030 customers will save $42 on electric water heating and $ 170 on EV operation under a high electrification scenario as compared to a scenario with no additional electrification.
Declaration of Competing Interest Mohit Chhabra is employed by NRDC, a non-profit environmental advocacy organization. Acknowledgments The authors wish to thank Alex Jackson, and members of the PG&E finance team for their inputs to our analysis. Any remaining errors are our own. Catherine Hay was funded by Schneider Fellowship from Stanford University.
Appendix A Detailed Methodology and Key Assumptions (1) Forecasting Electric Rates To forecast electric rates, we first forecasted PG&E’s total revenue requirements which is one of the major driving forces behind the overall level of utility rates (California Public Utilities Commission 2017). This was accomplished by studying past trends in PG&E’s operating expenses, PG&E’s spending on expanding its capital investments or “rate base”, and the rate of return received by PG&E on its rate base capital investments. Future revenue requirements are estimated using Eq. 1. (1)
TRR = OE + r × (RB )
Where: TRR = total revenue requirement ($) OE = operating expenses ($) r = rate of return on rate base (%) RB = rate base ($) The process for calculating operating expenses, rate of return on rate base, and rate base are discussed further later in this Appendix. The total revenue requirement is then separated into its gas and electric utility components. For this analysis, we assume that the total gas revenue requirement increases at 2.9 %, which is in-line with the historical average annual increase of the gas revenue requirement (California Public Utilities Commission (CPUC) Energy Division 2019). We held the rate of change of the revenue requirement for the gas business constant throughout all three scenarios. Once the total electric revenue requirement is determined, the average residential for each year is calculated in the following manner per Eq. 2:
TRR e × p = ARR e S × s
(2)
Where: TRR e = total electric revenue requirement ($) for a given year p = residential revenues as % of total revenue (%) calculated using historic data S = total sales (kWh) forecasted for that same year s = residential sales as % of total sales (%) ARR e = average residential electric rate ($/kWh) for that year The average contribution of residential revenues to total revenue, p, was calculated to be 42 % based on historic sales data (U.S. Energy Information Administration (EIA), 2019). Residential sales as a percent of total sales, s, is 32 % (California Energy Commission (CEC), 2018). These values stay constant through 2030 and in all three scenarios.11 Our forecasts assume that electric sales will grow at 0.70 % year-over-year (YOY) in the Counterfactual and the Base scenarios. This growth rate is based on the average growth rate of the CEC demand forecast (California Energy Commission (CEC) 2018). In the high electrification scenario, we account for additional building and transportation electrification by increasing the sales growth per year. This electrification driven additional electric sales, presented in Table 1, are derived from the CEC study Deep Decarbonization in a High Renewables Future: Updated Results from the California PATHWAYS Model (Energy and Environmental Economics (E3), 2018).12 (3) Key Assumptions (3) Operating Expenses. Operating expenses are calculated as follows (Eq. (3)):
OE = COE + COG + OM + DA
(3)
Where: COE = cost of electricity purchases ($) COG = cost of gas sold ($) OM = operating and maintenance (O&M) expenses ($) DA = depreciation, amortization, and decommissioning (D&A) expenses ($) The values applied for each of these variables is presented in Table 2, the rationale behind applying these variables is explained in the following 11
Electric rate structures for each sector vary considerably. E.g., Average PG&E rates are approximately $0.21 in the residential sector, $0.195 in the agricultural, and $0.15 in the industrial sector in 2018. This variation has to do with past policy decisions as much as actual expenses associated with each sector. This analysis preserves this historic inter-sector difference in electric rates. 12 This CEC study determines the amount of building and transportation electrification necessary to realize California’s objective of a carbon neutral economy by 2045. See Figure 13, page 39 of the CEC study. 5
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paragraph. The cost of electricity purchased by a utility includes (1) costs associated in buying electricity from third party electricity generators and (2) costs of fuel purchased for use in the utilities’ own generation facilities.
• In the counterfactual and base scenarios, we assume that this cost of purchased electricity remains constant through 2030 (in the absence of •
•
better data). Although renewable electricity prices have been decreasing in recent years, to comply with California’s emissions reduction targets PG&E will have to sign more renewable energy contracts. How these counterbalancing effects interact is very uncertain. In the high electrification scenario, we assume that the cost of purchased power will increase at a rate of 0.75 % per year. The levels of electrification assumed increase electric sales at the rate of 1.5 % per year. The excess electricity required to meet this level of electrification is likely to come from solar and wind energy contracts, the costs of both have been steadily declining. We considered the bounds of increase in the cost of utility electricity purchases to be 1.5 % on the higher end (increase in proportion to the increase in load) and 0 on the lower end (increased electric demand is counterbalanced by the decline in renewable energy cost). We assumed that cost of purchased power will increase at the rate of 0.75 % per year as it is in our theoretical upper and lower bound. For the change in the cost of natural gas, we use the average annual change in forecasted natural gas prices in California from the Avoided Cost Calculator (California Public Utilities Commission (CPUC) 2019).
O&M expenses have historically grown at 1 % per year and we apply this growth rate in the Counterfactual scenario per PG&E 10k filings from 2014 through 2018 (PG&E Corporation, 2018). In the base and high electrification scenarios, we assume higher O&M expenses to account for additional operating expenses due to wildfire safety plan investments as illustrated by PG&E’s quarterly earnings presentations (PG&E Corporation, 2019a). D&A expenses were assumed to be 8 % of the total rate base in all scenarios; this assumption was based on studying historical data and conversations with PG&E analysts. (PG&E Corporation, 2018). This assumption remains constant for all scenarios. 13. Rate of Return on Rate Base. The California Public Utilities Commission (CPUC) authorizes the utility’s cost of capital (CoC)13 and capital structure14 through specific regulatory proceedings.15 Using the values shown in Table 3 below, Eq. 4 can be used to find the rate of return on rate base.
(4)
r = E × ROE + D × COD + PE × RPE
Where: E = equity as a percent of capital structure (%) ROE = return on equity (%) D = debt as percent of capital structure (%) COD = cost of debt (%) PE = preferred equity as a percent of capital structure (%) RPE = return on preferred equity (%) For this analysis, we use the 2019 authorized rates of return and capital structure. Although PG&E has requested a 12 % ROE, since it has not been approved, we use the previously authorized value of 10.25 % (Table 3) (Pacific Gas and Electric, 2019).16 These values are held constant throughout the three scenarios since these are the authorized amounts that PG&E is allowed to recover. Rate Base. A utility’s rate base, as explained above, is authorized by the CPUC and FERC through multiple regulatory proceedings, this rate base comprises of all the capital and assets that the utility owns. The CPUC allows the to earn a rate of return on this rate base. The assumed year-overyear (YOY) percent increases in PG&E’s rate base are shown in Table 4 below. These annual changes in rate base are calculated using historical rate base amounts and PG&E’s expected rate base growth from PG&E’s recent business updates (PG&E Corporation, 2019b). In the counterfactual scenario, a historical increase in rate base before the 2017 and 2018 wildfires is used through 2030 (PG&E Corporation, 2017) to understand how the PG&E’s rate base would’ve evolved in the absence of these recent wildfires. For the other two scenarios, the forecasted rate base from PG&E’s most recent business updates are used for years 2019–2023 (PG&E Corporation, 2019a). The requested rate bases are partially higher due to increased capital investment after the fires.
California Energy Commission (CEC) staff, 2017. "California Regular Gasoline Price Cases (2015 Dollars Per Gallon)." 2017 Integrated Energy Policy Report (IEPR). . https:// ww2.energy.ca.gov/2017_energypolicy/. California Energy Commission, 2018. 2018 Integrated Energy Policy Report Update, Volume II. Accessed September 3, 2019. . https://ww2.energy.ca.gov/ 2018publications/CEC-100-2018-001/CEC-100-2018-001-V2-CMF.pdf. California Public Utilities Commission (CPUC), 2019a. 2019 Natural Gas Avoided Cost Calculator. https://www.cpuc.ca.gov/General.aspx?id=5267. California Public Utilities Commission (CPUC), 2019b. Actions to Limit Utility Costs and Rates, Public Utilities Code Section 913.1 Annual Report to the Governor and Legislature. . https://www.cpuc.ca.gov/General.aspx?id=6442460031. California Public Utilities Commission (CPUC) Energy Division, 2019. California Electric and Gas Utility Cost Report, AB 67 Annual Report to the Governor and Legislature. . https://www.cpuc.ca.gov/energy_reports/.
References Bedsworth, Louise, Cayan, Dan, Guido, Franco, Fisher, Leah, Ziaja, Sonya, 2018. "Statewide Summary Report. California’s Fourth Climate Change Assessment." California Governor’s Office of Planning and Research, Scripps Institution of Oceanography, California Energy Commission, California Public Utilities Commission. Accessed September 3, 2019. . https://www.energy.ca.gov/sites/ default/files/2019-07/Statewide%20Reports-%20SUM-CCCA4-2018-013% 20Statewide%20Summary%20Report.pdf. California Energy Commission (CEC), 2018. California Energy Demand 2018-2030 Baseline Forecast-Mid Demand Case, Electricity Sales by Sector (GWh)." 2017 Integrated Energy Policy Report (IEPR). December. Accessed July 22, 2019. . https://efiling.energy.ca.gov/Lists/DocketLog.aspx?docketnumber=17-IEPR-03.
13 Per the CPUC, the CoC is “is the weighted average cost of debt, preferred equity, and common stock, a utility has issued to finance its investments. Return on Equity (ROE) is the return to common equity.” See the Commission website for further details: https://www.cpuc.ca.gov/General.aspx?id=10457 14 The capital structure of a utility describes the relative amount of shareholder equity and debt that constitute a utility’s total ratebase. See https://www.cpuc.ca. gov/General.aspx?id=12095 15 See list of CPUC proceedings that address cost of capital: https://www.cpuc.ca.gov/General.aspx?id=10479 16 Utilities are not guaranteed to earn their authorized return. If the utility overspends then it will most likely not earn its authorized rate of return.
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C. Hay and M. Chhabra California Public Utilities Commission, 2019. How Are Utility Rates Set? Accessed September 3, 2019. https://www.cpuc.ca.gov/General.aspx?id=12185. California Public Utilities Commission, 2017. "Utility General Rate Case- A Manual for Regulatory Analysts." Policy and Planning Division, California Public Utilities Commission (CPUC). https://www.cpuc.ca.gov/uploadedFiles/CPUC_Public_ Website/Content/About_Us/Organization/Divisions/Policy_and_Planning/PPD_ Work/PPD_Work_Products_(2014_forward)/PPD%20General%20Rate%20Case %20Manual.pdf. Energy and Environmental Economics (E3), 2018. "Deep Decarbonization in a High Renewables Future: Updated Results from the California pathways Model." Final Project Report, Energy Research and Development Division. . https://www.ethree. com/wp-content/uploads/2018/06/Deep_Decarbonization_in_a_High_Renewables_ Future_CEC-500-2018-012-1.pdf. Pacific Gas and Electric (PG&E) Company, 2019. Cost of Capital 2020 Supplemental Testimony. August 1. file://C:/Users/chay/Downloads/ CostofCapital2020_Test_PGE_20190801_573573.pdf. . PG&E Corporation, 2019a. 2019 First Quarter Earnings. May 2. http://s1.q4cdn.com/ 880135780/files/doc_financials/2019/q1/Earnings-Presentation-Q1-2019_Final.pdf. PG&E Corporation, 2019b. 2019 Second Quarter Earnings. August 9. http://s1.q4cdn. com/880135780/files/doc_financials/2019/q2/Earnings-Presentation-Q2-2019_ FINAL.pdf. PG&E Corporation, 2017. Business Update. July 28. http://s1.q4cdn.com/880135780/ files/doc_downloads/2018/July-2017-Business-Update.pdf. PG&E Corporation, 2018. Form 10-K 2018. http://investor.pgecorp.com/financials/sec-
filings/default.aspx. Sivak, Michael, Schoettle, Brandon, 2018. Relative Costs of Driving Electric and Gasoline Vehicles in the Individual U.S. States. The University of Michigan http://umich.edu/ ∼umtriswt/PDF/SWT-2018-1.pdf. U.S. Energy Information Administration (EIA), 2019. Form EIA-861M. August 29. https://www.eia.gov/electricity/data/eia861m/. Westerling, A.L., 2018. Wildfire simulations for California’s fourth climate change assessment: projecting changes in extreme wildfire events with a warming climate. California’s Fourth Climate Change Assessment, California energy Commission. Accessed September 3, 2019. http://www.climateassessment.ca.gov/techreports/ docs/20180827-Projections_CCCA4-CEC-2018-014.pdf. Catherine A. Hay is a M.S. student in the Atmosphere and Energy program in Civil and Environmental Engineering at Stanford University. Prior to graduate school, Catherine Hay was an analyst in the fixed income group at Goldman Sachs in New York for three years. She holds a B.S. in Chemical Engineering from Brown University. Mohit Chhabra is a Senior Scientist at the San Francisco office of the Natural Resources Defense Council (NRDC). Mohit Chhabra focuses on affecting policy to accelerate the transition to a sustainable and clean energy future. He provides analysis and strategic guidance to policymakers and other stakeholders at the state, regional, and national levels.
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The impact of wildfires and beneficial electrification on electricity rates in PG&E’s service territory
T
Catherine Hay, Mohit Chhabra (M.S.)* Natural Resources Defense Council San Francisco, CA, United States
ARTICLE INFO
ABSTRACT
Keywords: Electric Rates Wildfires Electrification
Building and transport electrification, an essential strategy to California’s carbon reduction goals, requires affordable electricity for customer adoption. We estimate the costs borne by the electric sector for its involvement in the 2017 and 2018 wildfires in Northern California to be significant and cause residential electric rates in PG& E territory to increase from 23 cents/kWh (2018) to 42 cents/kWh (2030). This rate increase could be limited to 35 cents/kWh through proactive transportation and building electrification.
1. Introduction 1.1. Background on the problem Buildings and transportation are a major source of greenhouse gas emissions (GHG) in California, responsible for over 60 % of GHG emissions in the state (California Energy Commission, 2018). To comply with the state’s carbon reduction goals of 40 % reduction below 1990 levels, and carbon neutrality, large scale electrification of transportation and buildings are required.1 A recent state-sponsored study estimates that the lowest-cost and most plausible pathway for the state to achieve carbon neutrality by 2045 requires electrification of energy services, especially the transportation and building sectors (Bedsworth et al., 2018). The viability of switching to electricity as a heating and transportation fuel depends in part on keeping the price of electricity affordable for Californians in absolute terms and relative to future gasoline and natural gas prices. Electricity prices in California have been rising steadily since 2000 and the recent catastrophic wildfires will put further upward pressure on electric rates (California Public Utilities Commission (CPUC), 2019a). Although electric rates in California have traditionally been higher than average rates in the United States,
electric bills in California have been lower because of lower energy usage in the state. However, as wildfires continue to occur in the state with increasing magnitude and frequency, uncertainty remains on how much utilities will bear the costs of fires, it is important to understand the impact recent state legislation in response to wildfires has had on electric rates (Westerling, 2018). In this paper, we estimate (1) the impact of the 2017 Northern California wildfires and Camp Wildfire on average residential electric rates2, (2) the extent to which an increase in these electric rates can be counteracted through transportation and building electrification and (3) the resultant impact of these forecasted rates on customer-economics of switching to electricity as a heating and transportation fuel. 1.2. Background on electric rates and utility revenue requirement The average electric rate for a customer class can be estimated by dividing the utility’s total revenue requirement for each customer class by the electric consumption of that customer class.3 The total revenue requirement in California is defined as the amount of revenue a utility is allowed to earn by regulatory agencies to be able to provide reliable service to customers and earn a fair rate of return for shareholders on utility investments.
Abbreviations: AB, Assembly Bill; CCAs, community choice aggregators; CEC, California energy commission; CPI, consumer price index; CPUC, California public utility commission; ERRA, energy resource recovery account; EV, electric vehicles; FERC, federal energy regulatory commission; ICE, internal combustion engine; IOU, investor owned utility; GRC, general rate case; GWh, gigawatt-hour; kWh, kilowatt-hour; PG&E, Pacific Gas and Electric; PPAs, power purchase agreements; PPPs, public purpose programs; ROR, rate of return; SAR, system average rate; SB, Senate Bill; YOY, year-over-year ⁎ Corresponding author. E-mail address: [email protected] (M. Chhabra). 1 Assembly Bill (AB) 32, Senate Bill (SB) 100, and the governor’s Executive Order meet state-wide emission targets. 2 This impact is based on the costs pertaining to these wildfires that we know are to be borne by the electric sector at the time of writing this paper. 3 This simplified calculation does not consider sub-categories within each customer class. This is aligned with the intent of the paper: to understand the on-average impact of state policies on average residential electric rates in PG&E service territory. https://doi.org/10.1016/j.tej.2020.106710
1040-6190/ © 2020 Elsevier Inc. All rights reserved.
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The total revenue requirement for an investor owned electric utility in California is determined through many different proceedings at the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC).4,5 Given this complex process for estimating the total revenue requirements for utilities, there are a variety of methods that can be used to decompose and better understand the constituent elements of a utilities total revenue requirement. Fig. 1 illustrates three different ways to decompose Pacific Gas and Electric’s (PG&E) revenue requirement.
• By utility service type: PG&E’s revenue requirement can be broken
•
•
down into the following categories of service provided by the utility: generation (50 %), distribution (30 %), transmission (10 %), public purpose programs (PPPs) (6 %), bonds and fees (4 %), and nuclear decommissioning (< 1 %) (California Public Utilities Commission (CPUC) Energy Division, 2019). By type of payment to the utility: we subcategorize payments made to the utilities as either payments to recuperate operating expenses (e.g. operations and maintenance, cost of purchasing electricity), or payments to earn a rate of return on capital investments made by the utility.6 Operating expenses are equal to the sum of the costs realized to operate the electric grid, purchase power, and maintain business operations for the utility’s customers. A utility can recover its operating expenses annually.7 In this analysis, we apply this method to forecast PG&E’s revenue requirement because it best allows us to assign costs associated with wildfires to their appropriate category. We further explain this process in Section 3.1. California Public Utilities Commission (CPUC), 2019b By proceeding: Here we break out the revenue requirement based on which proceeding these revenue requirements are litigated and determined.
Fig. 1. PG&E 2018 Revenue Requirement Decomposition (California Public Utilities Commission (CPUC) Energy Division 2019).
customer in PG&E’s service territory and are thus agnostic to which load serving entity (LSE) serves the customer. Moreover, the results of this analysis are meant to represent the order of magnitude of change in electric rates expected from the phenomena studied for the average residential customer (as opposed to a precise forecast of electric rates). 2.2. Future scenarios modeled In order to understand the impact of the wildfires on electric rates and future impact of transportation and building electrification, we developed three different future-scenarios. 2.2.1. Counterfactual (“No-Wildfire”) scenario A scenario that excludes the impact of 2017 Northern California and 2018 Camp wildfires and the impact of the related legislation forms the basis of this analysis. This Counterfactual, No-Wildfire scenario allowed us to extrapolate utility expenses without the confounding impact of recent wildfires. We then were able to layer-in the individual impact of each incremental impact we intend to study.
PG&E’s total revenue requirement is split among each customer class (e.g. residential, commercial, industrial, and agricultural) based on relative cost of serving each customer class (California Public Utilities Commission 2019) and between revenue requirement for electricity services and natural gas services to determine electric rates for each customer class.
2.2.2. Base scenario The base scenario layers-in the impact of existing wildfire legislation on electric rates. Wildfire legislation: SB 901 (2018, Dodd) requires IOUs to prepare wildfire mitigation plans (WMP) to be approved by the CPUC. AB 1054 (2019, Holden) requires utilities to conduct safety upgrades worth $5 billion and establishes a $21 billion “safety fund” to be able to pay any claims that may arise from future possible wildfires. We modeled PG& E’s portion of the spending associated with these $5 billion safety upgrades by estimating that PG&E will approximately spend an additional $3.2 billion on wildfire safety investment. The safety fund will be created by extending an existing bond charge, approximately 0.5 cents per kWh, and is modeled as such.
2. Analysis context and methodology 2.1. Analysis results illustrate the impact on average residential customer rates in PG&E transmission and distribution territory Electric customers within PG&E’s transmission and distribution area are served electricity by multiple community choice aggregators (CCA) in addition to PG&E. Wildfire costs, as they pertain to the transmission and distribution infrastructure, will be borne by all customers in PG&E service territory independent of customer class, and independent of who purchases the electricity on behalf of the customer (PG&E or a CCA). Our analysis and results are applicable to an average residential
2.2.3. High electrification scenario The high electrification scenario builds off the base scenario by adding-in the rate impact of increased levels of building and transportation electrification necessary to meet California’s economy wide carbon reduction goals. The details of this step are further explained in the Appendix to this paper. In addition to higher levels of electrification, this scenario also modeled rate impacts of SB100. SB100 requires retail electricity to be carbon free by 2045. This will result in additional procurement of renewable contracts by utilities
4 General Rate Case (GRC), Energy Resource Recovery Account (ERRA), Transmission Owner (TO) rate case, specific program area proceedings such as a proceeding specific to energy efficiency. 5 The FERC oversees revenue related to transmission costs through a Transmission Owner rate case proceeding. 6 Utility owned assets and capital are collectively referred to as the utility rate base, and the earnings from these investments are referred to as the utility’s return on rate base. This paper applies simplified calculations to determine utility earnings that does not take into account or separate greenhouse gas emission credits and other smaller revenue requirement elements such as taxes as their effects on our analysis are likely small. 7 More tree trimming will increase operating expenses whereas new grid infrastructure will increase rate base that the utility earns a rate of return on (approximately 7%).
3. Methodology Details of the methodology applied to forecast electric rates for each scenario is presented in the Appendix to this paper. This section presents a summary of this methodology. The first step is to forecast PG&E’s total revenue requirements, the 2
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Fig. 2. Electricity Rates Through 2030 by Scenario Type.
Fig. 3. Annual EV and ICE Fuel Consumption in PG&E Service Territory for Each Scenario Modeled.
driving force behind the overall level of utility rates (California Public Utilities Commission 2017), by studying past trends in PG&E’s operating expenses, PG&E’s spending on expanding its capital investments or “rate base”, and the rate of return received by PG&E on its rate base capital investments. Future total revenue requirements are estimated using Eq. (1).
TRR = OE + r × (RB )
2030 are expected to increase from $1,933 to $2,469 because of increased utility spending as a result of the recent wildfires. Transportation and building electrification in line with California’s economy wide decarbonization goals limits this bill increase to $2,132 in 2030 thereby savings consumers $337 in 2030. These changes in future electric rates also impact consumer economics on adopting electric cars and water heaters as discussed in the following section.
(1)
Where: TRR = total revenue requirement ($) OE = operating expenses ($) r = rate of return on rate base (%) RB = rate base ($) This total revenue requirement is then separated into its gas and electric utility components using historical data (California Public Utilities Commission (CPUC) Energy Division, 2019). Once the total electric revenue requirement is determined, the average residential for each year is calculated in the following manner per Eq. (2) :
TRR e × p = ARR e S × s
4.2. End-use electrification Using the electric rates developed for each of the three scenarios, we compare the cost of switching fuel both from internal combustion engine (ICE) vehicles to electric vehicles (IC) as well as from gas water heaters to electric water heaters. 4.2.1. Transportation In our transportation comparison, we assume that both vehicles will drive 10,000 miles annually. The conventional gasoline vehicle will have a fuel efficiency of 25 miles per gallon, while the electric vehicle will drive 3.3 miles per kWh (Table 5). We use gasoline price forecasts from the CEC 2017 IEPR report for California (California Energy Commission (CEC) staff 2017). Electric vehicles in all three scenarios are more cost-effective than conventional gasoline vehicles in terms of fuel cost (see Fig. 3).8 EV drivers save between $750-$1000 annually from 2018 to 2030 on fuel. Cumulatively, this translates to EV drivers saving over $10,000 on fuel costs. On average, EV drivers save $54 more per year in the high electrification scenario compared to the base case. Thus, high levels of electrification will lead to customers adopting more electric vehicles due to the decrease in electric rates as a result of electrification.
(2)
Where: TRR e = total electric revenue requirement ($) for a given year p = residential revenues as % of total revenue (%) calculated using historic data S = total sales (kWh) forecasted for that same year s = residential sales as % of total sales (%) ARR e = average residential electric rate ($/kWh) for that year 4. Results and discussion 4.1. Electric rates by scenario This paper estimates average residential electric rates for all three scenarios considered in this analysis for each year through 2030. The results of our analysis, presented in Fig. 2, can be summarized as:
4.2.2. Water heaters Annual water heater operation costs to serve an average single-family home in PG&E service territory were calculated using electric rates derived under each and with the cost of operating a natural gas water heater.9,10 In the High Electrification scenario, switching from a natural
• In the Counterfactual scenario, which forecasts what the electric • •
rates would be if the 2017 and 2018 wildfires had not occurred, we estimate that average residential electric rates would increase from 23 cents/kWh in 2018 to 32 cents/kWh in 2030. In the Base scenario the electric rates increase from 23 cents/kWh in 2018 to 41 cents/kWh in 2030. This additional increase in electric rates is due to increased utility spending in response to the 2017 and 2018 wildfires as required by California legislature via SB901 and AB1054. This increase in electric rates can be curtailed to 35 cents/kWh in 2030 through aggressive electrification. Electrification puts downward pressure on electric rates by increasing the total amount of energy sales that fixed utility costs are spread.
8 To calculate electricity cost for EVs, this paper applies the average residential electric rate for each of the three scenarios studied. 9 We assume the input energy for the new gas heater is 131.8 therms and input energy for new electric heater is 742.5 kWh. Heat pump water heater consumption data are from study conducted by Ecotope for NRDC. Ecotope applied on-site HPWH performance data to develop calibrated models of HPWH performance for NRDC. We’ve used consumption data for the GE GeoSpring (2014) 50 gallons model. We then calculated an consumption for an equivalent gas water heater using energy factor data and simple engineering equations. 10 To calculate these energy inputs, we found the weighted average of base consumption for PG&E’s single-family population by climate zone of the GE 2014 Heat Pump Water Heater – medium cost and for a small gas storage water heater (0.60 EF – 0.639 EF). We used E3’s residential rate estimates for the high building electrification to estimate future natural gas residential rates.
For an average California residential customer, who consumes an average of 500 kW h per month, this means that annual electric bills in 3
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use electrification incentivize further electrification by keeping electric rates low. Thus, the adverse effects of an increase in electric rates due to the 2017 and 2018 wildfires can be somewhat mitigated via electrifying water heating and transportation. 5. Conclusion Wildfires and subsequent legislation will have a significant upward impact on average residential rates in PG&E’s service territory. Our analysis estimates that PG&E service territory’s average electric rates will increase from approximately 23 cents/kwh to more than 41 cents/ kWh in 2030 due in part to increased utility spending in response to recent wildfires in Northern California. Thus, making electricity less affordable compared to alternatives such as natural gas and gasoline.
Fig. 4. Annual Residential Water Heater Operating Cost for a Single-Family Home in PG&E Service Territory. Table 1 Building and transportation electrification demand assumptions.
Building Electrification (GWh) Transport Electrification (GWh)
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
– 366
– 415
– 469
– 605
– 756
– 1,040
59 1,196
141 1,513
265 1,498
431 1,528
627 1,708
844 2,019
Table 2 Operating expenses assumptions for three scenarios. Historical data pulled from PG&E 10-K reports (PG&E Corporation, 2018). YOY % change
Counterfactual
Base
High Electrification
Cost of Electricity O&M D&A
0.0 % 0.0 % 1.0 % 2.9 % Assumed to be 8 % of total rate base in all scenarios.
0.75 % 2.9 %
Table 3 Cost of capital and capital structure assumptions (PG&E Corporation, 2018). Cost Return on Equity 10.25 % (ROE Preferred Stock 5.60 % (RPE) Long-Term Debt 4.89 % (COD) Weighted Average Cost of Capital/ Rate of Return on Rate Base (r)
Capital Structure
Weighted Cost
52.00 % (E) 1.00 % (PE) 47.00 % (D)
5.33 0.06 2.30 7.69
% % % %
Table 4 Rate base annual growth rate assumptions for the different scenarios.
Rate base, YOY % change
Counterfactual
Base
High Electrification
4.47 %
5.81 %
5.81 %
Table 5 Transportation fuel cost comparison assumptions (Sivak and Schoettle 2018).
Total Miles Driven ICE Miles per gallon (mpg) EV Average Miles/kWh
Conventional
EV
10,000 25 –
10,000 – 3.3
Electrifying natural gas (space and water heating) and gasoline powered end uses (internal combustion engine cars) is critical to achieving California’s carbon reduction targets; both of which require lower electricity rates as compared to that of natural gas and gasoline. However, electrifying building natural gas-powered end-uses and gasoline powered transportation has the potential to mitigate some of this increase in electric rates by distributing utility costs over a larger sales base. Electrification, of the scale necessary to meet California’s carbon reduction goals through 2030, will have the impact of
gas water heater to a heat pump water heater saves the customer an average of $83 a year from 2019 through 2030. In the Base scenario, this annual average savings reduces to $69 per year. Fig. 4 presents the annual operating costs of water heaters in each scenario. Assuming a fifteen-year life of an average heat pump water heater, customers will save an additional $210 over the life of the water heater in operational costs when switching from a natural gas water heater to a heat pump water heater under a high electrification scenario. These additional customer savings again underscores the finding that high levels of end4
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constraining average PG&E residential electric rates to approximately 35 cents/ kWh in 2030. Electrification is thus a strategy not only to meet California’s carbon reduction goals but also to keep electricity affordable for Californians. Thus, forming a virtuous cycle, whereby increased levels of electrification makes further electrification a more economic prospect for future adopters. This study estimates that in 2030 customers will save $42 on electric water heating and $ 170 on EV operation under a high electrification scenario as compared to a scenario with no additional electrification.
Declaration of Competing Interest Mohit Chhabra is employed by NRDC, a non-profit environmental advocacy organization. Acknowledgments The authors wish to thank Alex Jackson, and members of the PG&E finance team for their inputs to our analysis. Any remaining errors are our own. Catherine Hay was funded by Schneider Fellowship from Stanford University.
Appendix A Detailed Methodology and Key Assumptions (1) Forecasting Electric Rates To forecast electric rates, we first forecasted PG&E’s total revenue requirements which is one of the major driving forces behind the overall level of utility rates (California Public Utilities Commission 2017). This was accomplished by studying past trends in PG&E’s operating expenses, PG&E’s spending on expanding its capital investments or “rate base”, and the rate of return received by PG&E on its rate base capital investments. Future revenue requirements are estimated using Eq. 1. (1)
TRR = OE + r × (RB )
Where: TRR = total revenue requirement ($) OE = operating expenses ($) r = rate of return on rate base (%) RB = rate base ($) The process for calculating operating expenses, rate of return on rate base, and rate base are discussed further later in this Appendix. The total revenue requirement is then separated into its gas and electric utility components. For this analysis, we assume that the total gas revenue requirement increases at 2.9 %, which is in-line with the historical average annual increase of the gas revenue requirement (California Public Utilities Commission (CPUC) Energy Division 2019). We held the rate of change of the revenue requirement for the gas business constant throughout all three scenarios. Once the total electric revenue requirement is determined, the average residential for each year is calculated in the following manner per Eq. 2:
TRR e × p = ARR e S × s
(2)
Where: TRR e = total electric revenue requirement ($) for a given year p = residential revenues as % of total revenue (%) calculated using historic data S = total sales (kWh) forecasted for that same year s = residential sales as % of total sales (%) ARR e = average residential electric rate ($/kWh) for that year The average contribution of residential revenues to total revenue, p, was calculated to be 42 % based on historic sales data (U.S. Energy Information Administration (EIA), 2019). Residential sales as a percent of total sales, s, is 32 % (California Energy Commission (CEC), 2018). These values stay constant through 2030 and in all three scenarios.11 Our forecasts assume that electric sales will grow at 0.70 % year-over-year (YOY) in the Counterfactual and the Base scenarios. This growth rate is based on the average growth rate of the CEC demand forecast (California Energy Commission (CEC) 2018). In the high electrification scenario, we account for additional building and transportation electrification by increasing the sales growth per year. This electrification driven additional electric sales, presented in Table 1, are derived from the CEC study Deep Decarbonization in a High Renewables Future: Updated Results from the California PATHWAYS Model (Energy and Environmental Economics (E3), 2018).12 (3) Key Assumptions (3) Operating Expenses. Operating expenses are calculated as follows (Eq. (3)):
OE = COE + COG + OM + DA
(3)
Where: COE = cost of electricity purchases ($) COG = cost of gas sold ($) OM = operating and maintenance (O&M) expenses ($) DA = depreciation, amortization, and decommissioning (D&A) expenses ($) The values applied for each of these variables is presented in Table 2, the rationale behind applying these variables is explained in the following 11
Electric rate structures for each sector vary considerably. E.g., Average PG&E rates are approximately $0.21 in the residential sector, $0.195 in the agricultural, and $0.15 in the industrial sector in 2018. This variation has to do with past policy decisions as much as actual expenses associated with each sector. This analysis preserves this historic inter-sector difference in electric rates. 12 This CEC study determines the amount of building and transportation electrification necessary to realize California’s objective of a carbon neutral economy by 2045. See Figure 13, page 39 of the CEC study. 5
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paragraph. The cost of electricity purchased by a utility includes (1) costs associated in buying electricity from third party electricity generators and (2) costs of fuel purchased for use in the utilities’ own generation facilities.
• In the counterfactual and base scenarios, we assume that this cost of purchased electricity remains constant through 2030 (in the absence of •
•
better data). Although renewable electricity prices have been decreasing in recent years, to comply with California’s emissions reduction targets PG&E will have to sign more renewable energy contracts. How these counterbalancing effects interact is very uncertain. In the high electrification scenario, we assume that the cost of purchased power will increase at a rate of 0.75 % per year. The levels of electrification assumed increase electric sales at the rate of 1.5 % per year. The excess electricity required to meet this level of electrification is likely to come from solar and wind energy contracts, the costs of both have been steadily declining. We considered the bounds of increase in the cost of utility electricity purchases to be 1.5 % on the higher end (increase in proportion to the increase in load) and 0 on the lower end (increased electric demand is counterbalanced by the decline in renewable energy cost). We assumed that cost of purchased power will increase at the rate of 0.75 % per year as it is in our theoretical upper and lower bound. For the change in the cost of natural gas, we use the average annual change in forecasted natural gas prices in California from the Avoided Cost Calculator (California Public Utilities Commission (CPUC) 2019).
O&M expenses have historically grown at 1 % per year and we apply this growth rate in the Counterfactual scenario per PG&E 10k filings from 2014 through 2018 (PG&E Corporation, 2018). In the base and high electrification scenarios, we assume higher O&M expenses to account for additional operating expenses due to wildfire safety plan investments as illustrated by PG&E’s quarterly earnings presentations (PG&E Corporation, 2019a). D&A expenses were assumed to be 8 % of the total rate base in all scenarios; this assumption was based on studying historical data and conversations with PG&E analysts. (PG&E Corporation, 2018). This assumption remains constant for all scenarios. 13. Rate of Return on Rate Base. The California Public Utilities Commission (CPUC) authorizes the utility’s cost of capital (CoC)13 and capital structure14 through specific regulatory proceedings.15 Using the values shown in Table 3 below, Eq. 4 can be used to find the rate of return on rate base.
(4)
r = E × ROE + D × COD + PE × RPE
Where: E = equity as a percent of capital structure (%) ROE = return on equity (%) D = debt as percent of capital structure (%) COD = cost of debt (%) PE = preferred equity as a percent of capital structure (%) RPE = return on preferred equity (%) For this analysis, we use the 2019 authorized rates of return and capital structure. Although PG&E has requested a 12 % ROE, since it has not been approved, we use the previously authorized value of 10.25 % (Table 3) (Pacific Gas and Electric, 2019).16 These values are held constant throughout the three scenarios since these are the authorized amounts that PG&E is allowed to recover. Rate Base. A utility’s rate base, as explained above, is authorized by the CPUC and FERC through multiple regulatory proceedings, this rate base comprises of all the capital and assets that the utility owns. The CPUC allows the to earn a rate of return on this rate base. The assumed year-overyear (YOY) percent increases in PG&E’s rate base are shown in Table 4 below. These annual changes in rate base are calculated using historical rate base amounts and PG&E’s expected rate base growth from PG&E’s recent business updates (PG&E Corporation, 2019b). In the counterfactual scenario, a historical increase in rate base before the 2017 and 2018 wildfires is used through 2030 (PG&E Corporation, 2017) to understand how the PG&E’s rate base would’ve evolved in the absence of these recent wildfires. For the other two scenarios, the forecasted rate base from PG&E’s most recent business updates are used for years 2019–2023 (PG&E Corporation, 2019a). The requested rate bases are partially higher due to increased capital investment after the fires.
California Energy Commission (CEC) staff, 2017. "California Regular Gasoline Price Cases (2015 Dollars Per Gallon)." 2017 Integrated Energy Policy Report (IEPR). . https:// ww2.energy.ca.gov/2017_energypolicy/. California Energy Commission, 2018. 2018 Integrated Energy Policy Report Update, Volume II. Accessed September 3, 2019. . https://ww2.energy.ca.gov/ 2018publications/CEC-100-2018-001/CEC-100-2018-001-V2-CMF.pdf. California Public Utilities Commission (CPUC), 2019a. 2019 Natural Gas Avoided Cost Calculator. https://www.cpuc.ca.gov/General.aspx?id=5267. California Public Utilities Commission (CPUC), 2019b. Actions to Limit Utility Costs and Rates, Public Utilities Code Section 913.1 Annual Report to the Governor and Legislature. . https://www.cpuc.ca.gov/General.aspx?id=6442460031. California Public Utilities Commission (CPUC) Energy Division, 2019. California Electric and Gas Utility Cost Report, AB 67 Annual Report to the Governor and Legislature. . https://www.cpuc.ca.gov/energy_reports/.
References Bedsworth, Louise, Cayan, Dan, Guido, Franco, Fisher, Leah, Ziaja, Sonya, 2018. "Statewide Summary Report. California’s Fourth Climate Change Assessment." California Governor’s Office of Planning and Research, Scripps Institution of Oceanography, California Energy Commission, California Public Utilities Commission. Accessed September 3, 2019. . https://www.energy.ca.gov/sites/ default/files/2019-07/Statewide%20Reports-%20SUM-CCCA4-2018-013% 20Statewide%20Summary%20Report.pdf. California Energy Commission (CEC), 2018. California Energy Demand 2018-2030 Baseline Forecast-Mid Demand Case, Electricity Sales by Sector (GWh)." 2017 Integrated Energy Policy Report (IEPR). December. Accessed July 22, 2019. . https://efiling.energy.ca.gov/Lists/DocketLog.aspx?docketnumber=17-IEPR-03.
13 Per the CPUC, the CoC is “is the weighted average cost of debt, preferred equity, and common stock, a utility has issued to finance its investments. Return on Equity (ROE) is the return to common equity.” See the Commission website for further details: https://www.cpuc.ca.gov/General.aspx?id=10457 14 The capital structure of a utility describes the relative amount of shareholder equity and debt that constitute a utility’s total ratebase. See https://www.cpuc.ca. gov/General.aspx?id=12095 15 See list of CPUC proceedings that address cost of capital: https://www.cpuc.ca.gov/General.aspx?id=10479 16 Utilities are not guaranteed to earn their authorized return. If the utility overspends then it will most likely not earn its authorized rate of return.
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C. Hay and M. Chhabra California Public Utilities Commission, 2019. How Are Utility Rates Set? Accessed September 3, 2019. https://www.cpuc.ca.gov/General.aspx?id=12185. California Public Utilities Commission, 2017. "Utility General Rate Case- A Manual for Regulatory Analysts." Policy and Planning Division, California Public Utilities Commission (CPUC). https://www.cpuc.ca.gov/uploadedFiles/CPUC_Public_ Website/Content/About_Us/Organization/Divisions/Policy_and_Planning/PPD_ Work/PPD_Work_Products_(2014_forward)/PPD%20General%20Rate%20Case %20Manual.pdf. Energy and Environmental Economics (E3), 2018. "Deep Decarbonization in a High Renewables Future: Updated Results from the California pathways Model." Final Project Report, Energy Research and Development Division. . https://www.ethree. com/wp-content/uploads/2018/06/Deep_Decarbonization_in_a_High_Renewables_ Future_CEC-500-2018-012-1.pdf. Pacific Gas and Electric (PG&E) Company, 2019. Cost of Capital 2020 Supplemental Testimony. August 1. file://C:/Users/chay/Downloads/ CostofCapital2020_Test_PGE_20190801_573573.pdf. . PG&E Corporation, 2019a. 2019 First Quarter Earnings. May 2. http://s1.q4cdn.com/ 880135780/files/doc_financials/2019/q1/Earnings-Presentation-Q1-2019_Final.pdf. PG&E Corporation, 2019b. 2019 Second Quarter Earnings. August 9. http://s1.q4cdn. com/880135780/files/doc_financials/2019/q2/Earnings-Presentation-Q2-2019_ FINAL.pdf. PG&E Corporation, 2017. Business Update. July 28. http://s1.q4cdn.com/880135780/ files/doc_downloads/2018/July-2017-Business-Update.pdf. PG&E Corporation, 2018. Form 10-K 2018. http://investor.pgecorp.com/financials/sec-
filings/default.aspx. Sivak, Michael, Schoettle, Brandon, 2018. Relative Costs of Driving Electric and Gasoline Vehicles in the Individual U.S. States. The University of Michigan http://umich.edu/ ∼umtriswt/PDF/SWT-2018-1.pdf. U.S. Energy Information Administration (EIA), 2019. Form EIA-861M. August 29. https://www.eia.gov/electricity/data/eia861m/. Westerling, A.L., 2018. Wildfire simulations for California’s fourth climate change assessment: projecting changes in extreme wildfire events with a warming climate. California’s Fourth Climate Change Assessment, California energy Commission. Accessed September 3, 2019. http://www.climateassessment.ca.gov/techreports/ docs/20180827-Projections_CCCA4-CEC-2018-014.pdf. Catherine A. Hay is a M.S. student in the Atmosphere and Energy program in Civil and Environmental Engineering at Stanford University. Prior to graduate school, Catherine Hay was an analyst in the fixed income group at Goldman Sachs in New York for three years. She holds a B.S. in Chemical Engineering from Brown University. Mohit Chhabra is a Senior Scientist at the San Francisco office of the Natural Resources Defense Council (NRDC). Mohit Chhabra focuses on affecting policy to accelerate the transition to a sustainable and clean energy future. He provides analysis and strategic guidance to policymakers and other stakeholders at the state, regional, and national levels.
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