HomeMy WebLinkAboutStaff Report 2506-4889CITY OF PALO ALTO
Finance Committee
Regular Meeting
Tuesday, September 02, 2025
Agenda Item
1.Recommend the City Council Adopt Voluntary Residential Electric Service Time-of-Use
Rates (E-1 TOU); CEQA Status: Not a Project Staff Presentation
Finance Committee
Staff Report
From: City Manager
Report Type: ACTION ITEMS
Lead Department: Utilities
Meeting Date: September 2, 2025
Report #:2506-4899
TITLE
Recommend the City Council Adopt Voluntary Residential Electric Service Time-of-Use Rates (E-
1 TOU); CEQA Status: Not a Project
RECOMMENDATION
The Utilities Advisory Commission and staff recommends that the Finance Committee
recommend the City Council adopt a resolution (Attachment A: Resolution) adding voluntary Rate
Schedule E-1 Time of Use (TOU) applicable to separately metered single-family residential
dwellings receiving electric service effective January 1, 2026 (Attachment B: Rate Schedule E-1
TOU).
EXECUTIVE SUMMARY
The Utilities Advisory Commission and Staff recommend introducing a voluntary residential
electric time-of-use rate plan on January 1, 2026 (E-1 TOU Rate Schedule). Separately metered
single-family residential dwellings receiving electric service from the City of Palo Alto with
Advanced Metering Infrastructure (AMI) meters may opt-in to this new E-1 TOU rate plan.
The proposed E-1 TOU rates align with the requirements of Article XIII C of the California
Constitution (often referred to as Proposition 26) to align with the cost of electricity. The
proposed E-1 TOU rates also align with the cost of electricity at the time of use. The proposed E-1
TOU rates provide customers the opportunity to take advantage of lower-cost and lower carbon
intensity time periods for electric vehicle charging or other electric uses.
TOU rates are a type of electricity pricing where the cost of electricity varies depending on the
time of day the electricity is used. Under this structure, electricity prices are typically lower during
off-peak hours, when demand is low, and higher during peak hours, when the grid is under more
strain due to higher demand compared to available electricity supply. Staff considered the
marginal cost of energy, as well as several other factors described in detail below to determine
the hours of the day that each TOU rate applies.
BACKGROUND
At the December 4, 2024 UAC meeting, Staff presented preliminary rate proposals for FY 2026
and provided an update on TOU rates as an informational item for discussion purposes.1 On June
4, 2025, these TOU rate proposals were reviewed and unanimously recommended for approval
by the UAC (Staff Report #2503-4361)2.
Staff recommends a January 1, 2026 implementation date for E-1 TOU to allow sufficient time to
prepare for its implementation. Staff estimates that 95% of residential customers will have
electric AMI meters installed by the end of December 2025. The remaining 5% of residential
customers are estimated to receive AMI meters by April 2026. Customers will first need to have
an AMI meter installed to be eligible to participate in the E-1 TOU rate.
ANALYSIS
The Electric Utility’s rates are evaluated and implemented in compliance with cost-of-service
requirements set forth in the California Constitution and applicable statutory law. This E-1 TOU
recommendation reflects the proposed FY 2026 costs and revenues for the Electric Utility that
are reflected in the financial forecast that was approved by the Council on June 16, 2025, and the
“City of Palo Alto Electric Cost of Service and Rate Study” by EES Consulting, Inc. in 2023/2024 (FY
2024 COS Study), supplemented by EES’s April 1, 2025 memo on “Electric Time of Use Rate Design
for E-1: Residential Customer Class” (Attachment C: COSA Study’s E-1 TOU Supplement).
The new E-1 TOU rates are designed to generate the same FY 2026 revenue as the standard E-1
rates, assuming customers do not change their electric usage patterns. Because the number of
customers opting in to E-1 TOU will gradually increase over time, the revenue risk to the Electric
Utility will be minimal as adjustments to the rate will be implemented over time as more data is
available regarding changes in customers’ electric usage patterns.
These residential TOU rates align with the cost of electricity at the time of use. Residential
customers may opt-in to this rate to take advantage of lower-cost time periods for electric vehicle
charging and other appliances with flexible loads can also take advantage of this rate.
As presented in the COSA Study’s E-1 TOU Supplement, the hours of the day that each TOU rate
applies (peak, off-peak and super off-peak) or “TOU periods” are designed with consideration of
several factors including marginal cost of energy, distribution system capacity and peak demand,
greenhouse gas intensity of market energy, and best practices in ratemaking.
1 The transcript from the meeting is available on the City’s website:
https://cityofpaloalto.primegov.com/Public/CompiledDocument?meetingTemplateId=15106&compileOutputType
=1.
2 UAC Staff Report #2503-4361 on June 4, 2025
https://cityofpaloalto.primegov.com/Portal/viewer?id=0&type=7&uid=a193f374-f0af-479d-bf30-ce2b7a3c6a05
1. Marginal cost of energy
The TOU periods are structured to reflect the marginal cost of energy, which refers to the cost of
producing or purchasing one additional unit of electricity. This cost fluctuates throughout the day
based on overall demand, fuel availability, and market dynamics. By aligning TOU pricing periods
with periods of higher or lower marginal cost, utilities can send price signals that encourage
consumers to shift their energy usage to times when electricity is cheaper to purchase. This not
only reduces strain on the grid but also improves overall economic efficiency in the energy
market. Because of the large penetration of solar resources in California, the lowest priced
periods typically occur in the sunny mid-day hours, while the highest priced periods typically
occur in the evening hours just after sunset.
2. Distribution system capacity and peak demand
TOU periods are also influenced by the capacity of the distribution system and the timing of peak
demand. Electricity systems must be built to meet the highest expected load, even if those peaks
occur infrequently. By identifying and pricing peak hours higher, TOU rates encourage customers
to shift consumption away from peak periods, which enhances grid reliability and optimizes use
of existing infrastructure, delaying or reducing the need for costly infrastructure upgrades. This
also reduces the utility’s need to purchase additional local and system resource adequacy
capacity, as these procurement requirements are set based on the utility’s actual peak demand
levels.
3. Greenhouse gas intensity of market energy
Another important consideration in TOU design is the greenhouse gas (GHG) intensity of the
energy supply during different times of the day. Energy generated during peak hours often comes
from fossil-fuel-based plants that produce higher emissions compared to cleaner sources like
solar, which are more prevalent during mid-day hours. TOU rates can incentivize customers to
use electricity when the grid is powered by cleaner energy, thereby supporting emissions
reductions and climate goals. (Note that although CPAU has a carbon neutral electricity supply,
the utility is still responsible for countering the effects of the marginal emissions that occur as a
result of its electricity consumption through the purchase of additional renewable energy;
therefore, it lowers the utility’s costs to have customers use electricity primarily in lower
emissions periods.)
4. Best practices in ratemaking
TOU rate plans also reflect established best practices in utility ratemaking, which aim to balance
fairness, efficiency, and transparency. This involves designing rates that are cost-reflective,
encourage customer responsiveness, and promote long-term sustainability of the electric
system. Best practices ensure that TOU pricing is not only effective in achieving grid and
environmental objectives, but also understandable and equitable for customers, including
protections for vulnerable populations.
It has been shown that consumers are more able to shift energy use to lower-priced periods when
the high-priced period is shorter in duration. The recommended peak period is from 4 pm to 9
pm. This 5-hour period captures the highest marginal energy costs, the highest average GHG
intensities, and the timing of both the distribution system peak and residential class peak
demand.
The Residential TOU program will enable CPAU to gauge customer interest in electric TOU rates
and assess the behavioral changes of customers who opt into these TOU rates. In the absence of
any E-1 TOU customer data, the TOU rate design assumed the E-1 customer class load profile and
the TOU rates were designed to recover the same revenue requirement.
Table 1 shows the proposed E-1 TOU rates, compared to the proposed E-1 rates for FY 2026.
Table 1: FY 2026 Rates for E-1 and E-1 TOU
Commodity Distribution Public
Benefits Total
E-1 TOU Rate Schedule – Proposed in this Staff Report, effective date January 1, 2026
E-1 TOU Volumetric Rate, $/kWh (No Baseline)
Summer: June 1 – September 30
Peak: 4pm to 9pm 0.23354 0.09351 0.00604 0.33309
Off-Peak: 9pm to 9am, 3pm to 4pm 0.08249 0.09351 0.00604 0.18204
Super Off-Peak: 9am to 3pm 0.06690 0.09351 0.00604 0.16645
Winter: October 1 – May 31
Peak: 4pm to 9pm 0.16705 0.09351 0.00604 0.26660
Off-Peak: 9pm to 9am, 3pm to 4pm 0.11033 0.09351 0.00604 0.20988
Super Off-Peak: 9am to 3pm 0.07835 0.09351 0.00604 0.17790
E-1 TOU Customer Charge
Customer Charge, $/month 5.15
E-1 Rate Schedule – Effective date July 1, 2025
E-1 Volumetric Rate, $/kWh (Baseline at 450 kWh)
E-1 Tier 1 (up to 450 kWh)0.10373 0.09593 0.00604 0.20570
E-1 Tier 2 (over 450 kWh)0.13372 0.08968 0.00604 0.22944
E-1 TOU and E-1 Customer Charge
Customer Charge, $/month 5.15
Figures 1 and 2 below show the E-1 and E-1 TOU volumetric rates for summer and winter for FY
2026.
Figure 1: E-1 (Tier 1 and Tier 2) and Summer E-1 TOU Volumetric Rates for FY 2026
Figure 2: E-1 (Tier 1 and Tier 2) and Winter E-1 TOU Volumetric Rates for FY 2026
Customers electing the E-1 TOU rate plan must remain on the plan for a minimum of six
months. After six months, E-1 TOU customers may request a change to any applicable rate
schedule; however, once a customer switches to a rate schedule other than E-1 TOU, they cannot
re-elect E-1 TOU for the next 12 billing cycles. Other utilities have similar restrictions regarding
customers switching between rate plans3. For Palo Alto, six months is a reasonable balance
between offering flexibility to customers and protecting the utility from customers switching rate
plans frequently based upon which season the rate plan benefits the customer, thereby
generating additional administration for the utility.
3 This proposed rule is slightly different from that implemented by California’s three largest electric utilities. For
PG&E, customers may request a rate plan change up to two times in a rolling 12-month period; however, once a
customer makes the 2nd rate change, they will have to remain on that plan for the next 12 billing cycles. For
Southern California Edison and San Diego Gas & Electric Company, customers switching to TOU rate will not be
able to make another switch for a full 12 months.
Net Energy Metering (NEM) customers4 will not be eligible to opt-in to the Residential TOU rate
plan due to existing constraints in the billing system. Staff is working to address these constraints.
Implementation Plan
Staff has begun the process of updating the billing system to accept energy consumption data
from the AMI system to compute electric TOU customer bills. Planning and implementation
activities include modifying the billing system and developing logistics related to customer
enrollment, customer informational tools and communication plan. To ensure a smooth roll-out
of this new rate, staff anticipates an initial testing period with a small group of beta customers
beginning in January 2026 followed by a modulated increase in customer enrollments. Staff plans
to present marketing and communication and customer-centric details of this new rate
implementation to the UAC in Fall 2025.
FISCAL/RESOURCE IMPACT
The rate level of E-1 TOU is based on the FY 2026 cost estimates and is therefore designed to
produce the same revenue increase percentage as that expected from the standard E-1 rates
adopted by Council effective July 1, 2025.
STAKEHOLDER ENGAGEMENT
Staff provided an update on the development of E-1 TOU rates at the December 4, 2024 UAC
meeting. On June 4, 2025, staff presented the TOU rate proposals to the UAC. Commissioners
reported that the UAC subcommittee had met with staff twice and commented that it is
important to communicate to customers why it is important to use electricity during the solar
production hours (energy is cleaner and cheaper) potentially using appropriate naming or
branding and that E-1 TOU rates would be even more impactful if the dollar impact of shifting
load to the super-off peak was greater. One Commissioner asked whether staff had considered
maximizing the price differential between the super off-peak and peak in order to provide more
of a financial incentive to customers and staff responded that different TOU periods were
examined and that changing the TOU periods did not change the resulting rates very much. The
UAC unanimously recommended approval of this proposal. The details of the meeting are
available on the City’s website at the following link:
https://cityofpaloalto.primegov.com/Portal/Meeting?meetingTemplateId=17431
Since the June 4, 2025 UAC meeting staff added the requirement that residential customers must
have an AMI meter installed in order to participate in the E-1 TOU rate schedule. This is reflected
in Attachment B.
4 NEM customers are those who receive compensation for the energy generated by photovoltaic systems installed
at their residences.
In October, staff plans to solicit UAC feedback on an implementation plan including details
regarding the plan for expanding the program in phases, the enrollment process, support that
will be provided to help customers make the decision regarding opting in to the TOU rates, and
the customer engagement plan . Additionally, staff plans to present the E-1 TOU rates to the City
Council in September 2025.
ENVIRONMENTAL REVIEW
The Finance Committee’s review and recommendation to the City Council on the E-1 TOU Rate
Plan does not meet the California Environmental Quality Act’s definition of a project, pursuant
to Public Resources Code Section 21065. Thus, no environmental review is required.
ATTACHMENTS
Attachment A: Resolution
Attachment B: Rate Schedule E-1 TOU
Attachment C: COSA Study’s E-1 TOU Supplement
APPROVED BY:
Alan Kurotori, Director Utilities
Staff: Lisa Bilir, Senior Resource Planner
* NOT YET APPROVED *
Attachment A
1
027032125
Resolution No. ____
Resolution of the Council of the City of Palo Alto Approving Utility Rate
Schedule E-1 TOU (Residential Electric Time of Use Service)
R E C I T A L S
A. Each year the City of Palo Alto (“City”) adopts Financial Forecasts or Plans for its utilities,
to ensure adequate revenue to fund operations with the goal of providing safe, reliable,
and sustainable utility services at cost-based rates. Council adopted the FY 2026 Electric
Financial Forecast on June 16, 2025.1
B. Pursuant to Chapter 12.20.010 of the Palo Alto Municipal Code, the Council of the City of
Palo Alto may by resolution adopt rules and regulations governing utility services, fees and
charges.
C. On Month Day, 2025, at a noticed public hearing, the City Council heard and approved the
proposed optional electric residential time-of use rates available for qualified residents.
The Council of the City of Palo Alto does hereby RESOLVE as follows:
SECTION 1. Pursuant to Section 12.20.010 of the Palo Alto Municipal Code, Utility Rate
Schedule E-1 TOU (Residential Electric Time of Use Service) shall become effective January 1,
2026;
SECTION 2. The Council finds that the revenue derived from the adoption of this
resolution shall be used only for the purpose set forth in Article VII, Section 2, of the Charter of
the City of Palo Alto.
SECTION 3. The Council finds that the fees and charges adopted by this resolution are
charges imposed for a specific government service or product provided directly to the payor that
are not provided to those not charged, and do not exceed the reasonable costs to the City of
providing the service or product.
SECTION 4. The Council finds that changing electric rates to introduce an optional
Residential Time of Use rate is not subject to the California Environmental Quality Act (CEQA),
pursuant to California Public Resources Code Sec. 21080(b)(8) and CEQA Guidelines Sec. 15273(a).
After reviewing the staff report and all attachments presented to Council, the Council
1
https://www.paloalto.gov/files/assets/public/v/2/agendas-minutes-reports/agendas-minutes/city-council-
agendas-minutes/2025/june-16/rates-attachments/finalized-attachment-d-exhibit-1-fy26-electric-utility-financial-
forecast-and-cip-detail.pdf
* NOT YET APPROVED *
Attachment A
2
027032125
incorporates these documents herein and finds that sufficient evidence has been presented
setting forth with specificity the basis for this claim of CEQA exemption.
INTRODUCED AND PASSED:
AYES:
NOES:
ABSENT:
ABSTENTIONS:
ATTEST:
City Clerk
Mayor
APPROVED AS TO FORM:
APPROVED:
Assistant City Attorney
City Manager
Director of Utilities
Director of Administrative Services
RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-1 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-1-TOU-1
Effective 1-1-2026
A. APPLICABILITY:
This voluntary Rate Schedule applies to separately metered single-family residential dwellings
receiving Electric Service from the City of Palo Alto Utilities (CPAU) who have an Advanced
Metering Infrastructure meter installed. This Rate Schedule is not available to Net Energy
Metered (NEM) customers and is provided at the sole discretion of CPAU.
B. TERRITORY:
This rate schedule applies everywhere the City of Palo Alto provides Electric Service.
C. UNBUNDLED RATES:
Per kilowatt-hour (per kWh)Commodity Distribution Public Benefits Total
Summer Period
Energy Charge
Peak $ 0.23354 $ 0.09351 $ 0.00604 $ 0.33309
Off-Peak 0.08249 0.09351 0.00604 0.18204
Super Off-Peak 0.06690 0.09351 0.00604 0.16645
Winter Period
Energy Charge
Peak $ 0.16705 $ 0.09351 $ 0.00604 $ 0.26660
Off-Peak 0.11033 0.09351 0.00604 0.20988
Super Off-Peak 0.07835 0.09351 0.00604 0.17790
Customer Charge ($/month)5.15
D. SPECIAL NOTES:
1. Calculation of Charges
The actual bill amount is calculated based on the applicable rates in Section C above and
adjusted for any applicable discounts, surcharges and/or taxes. On a Customer’s bill statement,
the bill amount may be broken down into appropriate components as calculated under Section C.
RESIDENTIAL ELECTRIC TIME OF USE SERVICE
UTILITY RATE SCHEDULE E-1 TOU
CITY OF PALO ALTO UTILITIES
Issued by the City Council
Sheet No E-1-TOU-2
Effective 1-1-2026
2. Definition of Seasonal Periods
Summer Period: Service from June 1 to September 30
Winter Period: Service from October 1 to May 31
SEASONAL RATE CHANGES: When the Billing Period includes use in both Summer and
Winter periods, usage will be prorated based on the number of days in each seasonal period, and
the Charges based on the applicable rates therein. For further discussion of bill calculation and
proration, refer to Rule and Regulation 11.
3. Definition of Time Periods
Peak: 4:00 p.m. to 9:00 p.m. Every day
Off-Peak: 9:00 p.m. to 9:00 a.m. Every day
3:00 p.m. to 4:00 p.m.
Super Off-Peak: 9:00 a.m. to 3:00 p.m. Every day
4. Changing Rate Schedules
Customers electing to be served under E-1 TOU must remain on said Rate Schedule for a
minimum of 6 months. Should the Customer so wish, at the end of 6 months, the Customer may
request a Rate Schedule change to any applicable City of Palo Alto full-service Rate Schedule as
is suitable to their kilowatt-hour usage. However, once a customer elects a rate other than E-1
TOU, they cannot re-elect E-TOU for the next 12 billing cycles.
{End}
16701 NE 80th Street Suite 102 Redmond, WA 98052 425-889-2700 Fax 866-611-3791
www.gdsassociates.com
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MEMORANDUM
TO Lisa Bilir
FROM Amber Gschwend
DATE April 1, 2025
RE Electric Time-of-Use Rate Design for E-1: Residential Customer Class
As part of the electric cost of service study, a rate design analysis is prepared to support the
implementation of time of use (TOU) rates for the E-1 class. It is estimated that over 90% of residential
customers will have Advanced Metering Infrastructure (AMI) installed by July 1, 2025, and optional TOU
rates could be offered at that time. The proposed rate developed in this memo would be implemented
on a voluntary basis. The bill impacts provided at the end of the analysis show that consumers with higher
use could benefit from the program. Bills at any usage level can be reduced with changes in behavior.
TOU RATE DESIGN BACKGROUND
Time-of-use rate design has many benefits including appropriate price signaling to customers and the
potential for customers to modify electric use to fall in periods of lower overall system costs, to reduce
bills and utility power costs. Investor-owned utilities (IOUs) in California have defaulted residential
customers to TOU rates, with the exception of low-income program customers.1
As a voluntary program, it is expected that customers who opt into the TOU rate would be those
customers who can modify electric consumption timing, and these customers may be more aware of their
energy use profiles in general. Customers with electric vehicles (EV) can benefit by choosing to charge
vehicles during lower energy cost periods. Under the current tiered rate, electric vehicle charging would
likely fall under the higher Tier 2 electric rate, based on higher household consumption. Therefore, the
TOU rate offers the opportunity for EV owners to reduce electric bills without increasing costs for other
customers. Additionally, when combined with demand response programs, TOU rates could also
incentivize customers to purchase programmable appliance controls (e.g., battery energy storage
systems, water heaters) further allowing customers to reduce electric usage during high-priced periods.
TOU program participation in the United States, when voluntary, typically ranges from 1% to 10% of the
total number of eligible households.2 As of 2023, approximately one in three residential customers in Palo
Alto own EVs, therefore, the adoption rate in Palo Alto is likely to be higher. If Palo Alto decides to
implement TOU as the default option, while allowing customers to opt back to a tiered rate option, TOU
program participation would likely increase to 75-90%. Alternatively, the City may require TOU rate design
for all customers in the class, resulting in 100% participation.
1 Pirro, Michael. The Evolution and Challenges of Time-of-Use Rate Designs. GridX. August 29, 2024. The Evolution
and Challenges of Time-of-Use Rate Designs.
2 Eligible households are those with appropriate meeting infrastructure or some other factor as determined by the
utility.
MEMORANDUM
Electric TOU Rate Design E-1
2
RECOMMENDED PALO ALTO RESIDENTIAL TOU PROGRAM
A voluntary E-1 TOU program will provide useful information to the City. Peak demand reduction
estimates can be made by comparing E-1 TOU participant demands to standard E-1 class demands over
the same period. This information will help the City plan for future program roll-out design as well as
reduce its future power costs. Based on PG&E’s program, it is expected that peak demand reduction on
the order of 3-6% could be achieved through TOU rate design.3 Note: The residential customer share of
Palo Alto’s overall peak demand is estimated at 12%, therefore, a reduction in residential class peak of 3-
6% results in an overall system peak reduction of 0.4 to 0.7%.
A voluntary program will also help the City determine with greater certainty the impact of TOU rate design
on utility revenues and expenses. As customers modify their behavior, it is expected that the revenue
collected will decrease and that power supply expenses will also decrease. It is recommended that the
TOU program revenues be analyzed annually, and retail rates updated so that the utility remains
financially stable. This initial rate design proposal considers the recovery of fixed and variable costs by
including fixed cost recovery in rate components that do not vary depending on the time of day energy is
used. This design mitigates potential impacts to revenue collection resulting from changed behavior from
TOU rate implementation.
Table 1 below summarizes the recommended TOU rate design methodology. The balance of the memo
describes the data and results of the analysis.
TABLE 1: RECOMMENDED TOU RATE DESIGN METHODOLOGY
Rate
Schedule Current Rate Design Recommended Rate Methodology
Residential
Electric
Service
•E-1: Not Time of Use
•Inclining Rate with Two Tiers
•Baseline Use (Tier 1) is 450
kWh/month
•Higher Use (Tier 2) is over 450
kWh/month
•E-1 TOU: Billing Periods Based on Differential in
Marginal Cost, Distribution System Capacity and Peak
Demand, Greenhouse Gas Intensity, and Best Practices
in Rate Design
•Commodity Rate Based on Marginal Cost
•Optional Rate Plan
TOU RATES FOR NET ENERGY METERED (NEM) CUSTOMERS
Due to technical hurdles associated with the electric billing system, CPAU is currently unable to implement
TOU rates for Net Energy Metered (NEM1 and NEM2)customers, who have energy generation and/or
storage capacity from solar panels and batteries. When CPAU overcomes NEM2 billing system hurdles,
TOU NEM2 will be developed.
3 Rate design and season impacts the peak demand reduction estimates. Pacific Gas and Electric (PG&E) study
authors note that peak demand impacts may diminish over time. Reference: Christensen Associates. 2023 Load
Impact Evaluation of Pacific Gas and Electric Company’s Residential Time-of-Use Rates Ex Post and Ex-Ante Report.
CALMAC Study ID PGE0496. April 1, 2024.
https://www.calmac.org/publications/2._PGE_2023_Res_TOU_Rpt_PUBLIC.pdf
MEMORANDUM
Electric TOU Rate Design E-1
3
REVENUE REQUIREMENT
The rate level for E-1 TOU is based on the FY2026 budget. The FY2026 budget is the FY2025 budget plus a
1% increase to power supply expenses, and an 11% increase for distribution expenses for an average
adjustment of 5% overall. Therefore, the proposed rates are equal to the FY2025 cost of service analysis
plus 5%. For E-1, the total revenue target for FY2026 is $29.4 million compared with $27.9 million for
FY2025. This is equivalent to 17% of the total electric utility retail revenue target of $172.9 million.
TOU COST JUSTIFICATION
TOU rate design is recommended to promote the efficient use of electricity by providing more accurate
cost-based pricing.
1. TOU rates are based on the marginal cost of electrical energy and electrical capacity at the time
of usage, reflecting accurate market price signals.
2. TOU rate design may lower the impact of increased EV charging on distribution feeder and
transformer loadings, by providing customer incentives to reduce or shift energy use away from
higher-priced periods.
3. TOU rates will provide customers with the opportunity to take advantage of lower-cost time
periods for EV charging or other electric use.
4. TOU rates support electrification by not penalizing high energy use if it occurs during lower market
priced periods.
Typically, the goal of TOU rate design is to provide more accurate cost-based pricing to retail customers.
In addition to this goal, TOU may also be used as a program to reduce overall power supply costs to the
utility and, to the extent possible, lower the peak load on the distribution system infrastructure. These
lowered costs are then passed to consumers through updated rate studies. A reduction in power costs
may be realized if customers conserve energy during high-priced periods, or if customers shift their energy
use to lower-priced periods. Similarly, reducing the peak loading of the distribution system will lower the
need for system upgrades and will also result in lower system energy losses.
DETERMINATION OF APPROPRIATE TOU PERIODS
As noted in Table 1, TOU periods are designed with consideration of several factors including:
1. Marginal cost of energy
2. Distribution system capacity and peak demand
3. Greenhouse gas intensity of market energy
4. Best practices in ratemaking.
Each of these considerations is described below.
Marginal Cost of Energy
The primary goal of the rate design is to accurately reflect the cost of service depending on the time of
day energy is used. Typically, higher-priced energy results from the combination of high electricity
demands and constrained resource output, which occurs after the sun sets when lower-cost solar
resources are no longer producing energy. The marginal cost of energy for the City is considered to be the
hourly market prices at the NP15 (North of Path 15) trading hub, adjusted for the Palo Alto service area
location. Hourly prices are commonly referred to as Default Load Aggregation Point (DLAP). The NP15
trading hub is the closest wholesale market transacting location. This pricing data is utilized in other areas
MEMORANDUM
Electric TOU Rate Design E-1
4
of the City’s utility planning and ratemaking and is the appropriate marginal cost metric for electric TOU
rate design.
Because of the large penetration of solar resources in the California markets, the highest priced periods
typically occur in the evening. This is demonstrated in the average hourly market pricing data shown in
Figure 1.4 These market prices are the marginal cost of electricity. In case of resource production surpluses
or shortages, the City would sell or purchase energy at these prices.
Figure 1 illustrates the average hourly market pricing for the 3-year period August 2021-July 2024. This
period is the most relevant to the analysis since it is the most recent data available. While the natural gas
shortage in winter 2023 inflated pricing in that period, removing that data from the analysis did not result
in significant differences. This is because the shape of the pricing curves is more important than the pricing
levels.
Figure 1 shows three periods for pricing. The red shaded period (peak) is the highest priced period
between 4 pm and 9 pm, averaging $95/MWh annually. The lowest priced period is between 9 am and 3
pm daily at $49/MWh on average (super off-peak). The average price for the remaining hours (off-peak)
is $65/MWh. The relative prices in these three periods are used to determine commodity rates.
FIGURE 1: AVERAGE HOURLY MARKET PRICES: 8/2021-7/2024
The recommended rate design has the same pricing periods for winter and summer seasons. Keeping the
time of day pricing periods the same year-round is simpler from the customer perspective and follows
Bonbright’s criteria of desirable rate structure where he emphasizes simplicity and understandability of
4 Average hourly prices for NP15 (DLAP Palo Alto), August 2021-July 2024.
$0
$20
$40
$60
$80
$100
$120
0:00 1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00
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MEMORANDUM
Electric TOU Rate Design E-1
5
rate design.5 A more complicated rate design with multiple TOU periods would more precisely reflect
marginal costs, but it would also be more difficult for customer understanding and implementation. For
this reason, a simpler rate design is recommended.
Distribution System Capacity and Peak Demand
The second consideration for the TOU periods is the peak at the distribution system level. This peak is the
maximum peak achieved when combining customer electric demands. A peak can be analyzed in various
ways such as system total (all City loads) or a subset of customers such as those being served from a
particular asset (substation, feeder, transformer). The peak on the distribution system drives distribution
system investments. Therefore, managing peak demands on the system can defer or avoid investments
in system expansion.
Typically, the distribution system peak coincides with the timing of higher-priced electricity. To test this,
the 12 monthly peaks (maximum demand) for the City’s entire system were analyzed. The three highest
monthly peaks on the system occur within the 4 pm to 9 pm time period. While the system peaks during
this time period, each class of customer contributes to that peak differently. Class system peaks help
define the capacity requirements across the distribution system. If the residential class peak were to occur
during a low marginal cost period for energy, the recommended TOU rate design could result in increased
distribution system costs. Shifting loads toward the residential class peak could result in an increase to
the distribution system capacity needs. To ensure that the recommended TOU rate periods do not place
undue upgrade costs on the distribution system, EES analyzed residential class load profile data.
At the time of this analysis, the City does not have hourly load profile data available for its residential
class. The City is currently installing AMI, which will provide usage data for future cost analysis and rate
making. Because hourly meter data is unavailable, EES evaluated hourly usage data for substation feeders:
Hopkins feeder 5 (HO5) and Hopkins feeder 7 (HO7). These feeders serve a total of 1,208 customers. Of
these, 1,200 customers are residential. Based on the customer count data, the hourly data from these
feeders should be a good approximation for residential load profiles for the City of Palo Alto. To further
test this theory, the hourly data from these feeders was compared with PG&E residential load profiles for
PG&E’s baseline territory “T.” This territory is adjacent to the City of Palo Alto and similar in climate. The
comparison further validates that the hourly Palo Alto feeder data is appropriate Palo Alto residential TOU
rate design.
Figure 2 compares the average hourly load shape for the 12 months beginning September 2022 for both
Hopkins feeders, and a similar-climate load shape from PG&E dynamic load profile data. The average is
calculated by averaging electric demand over the entire year for each hour ending (1-24). Figure 2 shows
normalized kW which is equal to kW in each hour divided by the average. Normalizing each curve makes
the curves comparable even if the data sets have different means.
5 Bonbright, James C. Principles of Public Utility Rates. Columbia University Press, 1961 (Reprinted 2005). Page 291.
powellgoldstein-bonbright-principlesofpublicutilityrates-1960-10-10.pdf
MEMORANDUM
Electric TOU Rate Design E-1
6
FIGURE 2: RESIDENTIAL HOURLY LOAD PROFILE AVERAGE: 9/2022-8/2023
Using the feeder data, an analysis of monthly peaks indicated that the 4 pm to 9 pm period captures the
two maximum feeder peaks (August and September for HO5 and December and September for HO7). This
is also supported in Figure 2 where the average daily peak occurs in the same window. Therefore, both
the system and feeder peak analyses support an on-peak period in the later afternoon/evening.
Palo Alto’s overall system peak, across all customer classes also occurs between 4 pm and 9 pm in the
highest 9 monthly peaks. This also supports setting the peak period between 4 pm and 9 pm.
Greenhouse Gas (GHG) Content
The third consideration for TOU periods is the carbon content of market purchases during lower-cost
periods. While not perfectly correlated, marginal cost, system peak demands, and high GHG content are
all highest during the same evening period. Figure 3, on the next page, shows the average hourly emission
intensity by month for energy transactions located within the management area of the California
Independent System Operator (CAISO). Emissions data are represented as metric tons (MT) of carbon
dioxide equivalent (CO2e) per megawatt hour (MWh) of electricity. The highest emission intensities are
between 7 pm and 7 am, when solar resources are not generating. The emission intensity data supports
a third TOU period during the day that represents the lower costs associated with both the low GHG
intensity and low marginal cost.
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MEMORANDUM
Electric TOU Rate Design E-1
7
FIGURE 3: AVERAGE CAISO EMISSION INTENSITY 2023, MT CO2 PER MWH
0:00 1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00
1 0.31 0.31 0.32 0.32 0.31 0.29 0.29 0.28 0.24 0.21 0.2 0.2 0.2 0.2 0.2 0.22 0.26 0.29 0.29 0.29 0.3 0.3 0.31 0.31
2 0.31 0.32 0.31 0.31 0.3 0.29 0.28 0.27 0.21 0.17 0.17 0.17 0.17 0.17 0.17 0.18 0.23 0.28 0.29 0.29 0.29 0.3 0.31 0.31
3 0.28 0.28 0.28 0.28 0.27 0.26 0.26 0.24 0.19 0.17 0.16 0.16 0.17 0.16 0.16 0.16 0.17 0.21 0.24 0.26 0.26 0.27 0.28 0.28
4 0.25 0.25 0.25 0.25 0.25 0.24 0.24 0.2 0.12 0.1 0.09 0.08 0.08 0.07 0.07 0.06 0.07 0.1 0.18 0.23 0.25 0.24 0.25 0.25
5 0.26 0.26 0.26 0.26 0.26 0.26 0.24 0.18 0.14 0.12 0.12 0.11 0.1 0.08 0.07 0.07 0.08 0.12 0.17 0.23 0.25 0.25 0.26 0.26
6 0.24 0.24 0.24 0.24 0.24 0.24 0.22 0.16 0.13 0.11 0.1 0.09 0.08 0.06 0.05 0.05 0.07 0.1 0.14 0.19 0.22 0.23 0.24 0.24
7 0.28 0.28 0.28 0.28 0.28 0.28 0.25 0.21 0.19 0.17 0.15 0.14 0.13 0.13 0.13 0.14 0.16 0.18 0.21 0.26 0.28 0.29 0.29 0.29
8 0.31 0.31 0.31 0.31 0.3 0.3 0.29 0.26 0.23 0.21 0.19 0.17 0.16 0.16 0.17 0.18 0.2 0.22 0.25 0.29 0.3 0.3 0.31 0.31
9 0.29 0.29 0.29 0.29 0.29 0.29 0.28 0.25 0.2 0.18 0.16 0.15 0.14 0.12 0.12 0.13 0.15 0.19 0.24 0.26 0.27 0.27 0.28 0.29
10 0.34 0.34 0.34 0.35 0.34 0.33 0.32 0.3 0.24 0.21 0.19 0.18 0.17 0.16 0.15 0.16 0.19 0.26 0.3 0.31 0.31 0.32 0.33 0.34
11 0.33 0.34 0.34 0.34 0.33 0.32 0.3 0.27 0.22 0.2 0.2 0.2 0.19 0.19 0.18 0.21 0.26 0.28 0.29 0.29 0.3 0.31 0.32 0.32
12 0.32 0.33 0.33 0.33 0.32 0.31 0.3 0.28 0.23 0.2 0.19 0.19 0.19 0.19 0.2 0.24 0.28 0.28 0.29 0.29 0.29 0.3 0.31 0.32
Hour Beginning
MEMORANDUM
Electric TOU Rate Design E-1
8
Best Practices
The last consideration for TOU periods is based on ratemaking best practices. First, it has been shown that
consumers are more able to shift energy use to lower priced periods when the high-priced period is
shorter in duration. As such, there is a trade-off in cost-based rates between peak usage pricing that is
significantly higher than off peak but for a shorter period versus smaller price differentials over a longer
period. The recommended peak period is from 4 pm to 9 pm. This 5-hour period captures high marginal
energy costs, high average GHG intensity, and the timing of both the distribution system peak and
residential class peak demand.
TOU RATE RECOMMENDATIONS
It is recommended that TOU rates be calculated for two seasons: summer and winter. The recommended
summer season is from June 1 through September 30. This choice of season is based on the annual system
peak typically in August or September and the local capacity requirement (determined by the annual
peak). Additionally, the seasonal rate design is necessary to pass through the differences in marginal costs
between seasons. In particular, the months of June through September are the peak cooling months
where the impact of solar on marginal costs is slightly less compared to winter. The recommended
seasonal definition results in a larger difference in pricing during summer hours as demonstrated by the
higher peak and lower troughs in Figure 4. Winter hours are priced closer together.
FIGURE 4: AVERAGE HOURLY MARKET PRICES BY SEASON: 8/2021-7/2024
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MEMORANDUM
Electric TOU Rate Design E-1
9
Based on the above analysis, the following TOU periods are recommended:
TABLE 2: RECOMMENDED TOU RATE PERIODS
Time of Day
Summer: June 1 – September 30 and Winter: October 1 – May 31
Peak 4 pm to 9 pm
Off-Peak 9 pm to 9 am and 3 pm to 4 pm
Super Off-Peak 9 am to 3 pm
Based on these TOU periods, marginal cost data, and the seasonal rate period, the recommended rate
differentials are developed. During the summer season, peak period prices average 85% higher than off-
peak prices. In winter, October 1 through May 31, the peak period prices average 23% higher than off-
peak prices. Super off-peak prices coincide with the time of day with the lowest marginal cost and lowest
greenhouse gas emission intensity. Prices during super off-peak periods during the summer are 19% lower
than off-peak summer prices and prices during super off-peak periods during the winter are 29% lower
than winter off-peak prices.
Table 3 summarizes the marginal cost data for the 3-year period analyzed, August 2021-July 2024. This
data was also analyzed by excluding the high winter prices in 2023 caused by natural gas shortages. This
event was unusual; however, the resulting price differentials between the recommended TOU periods
were not significantly different when the event is excluded.
Note that the marginal cost is not used directly for rate-setting. The marginal cost levels are adjusted to
reflect the utility’s actual all-in power costs; however, the ratio of peak, off-peak, and super off-peak prices
is maintained.6 By maintaining the relative cost of power, the resulting rates reflect the marginal cost
attributes while collecting the power supply costs allocated to residential customers in the cost of service
study.
6 This methodology differs from the Export Electricity Compensation rate (EEC) used to credit excess generation
value to Net Energy Metering (NEM) customers. The EEC rate considers the marginal cost of energy plus other costs
avoided when customers generate electricity locally.
MEMORANDUM
Electric TOU Rate Design E-1
10
TABLE 3: TOU MARGINAL COST: COMMODITY
Average DLAP1 Price
$/MWh
Difference from Seasonal
Off Peak Price
Summer: June 1 – September 30
Peak: 4 pm to 9 pm $99.98 + 85%
Off-Peak: 9 pm to 9 am and 3 pm to 4 pm $53.96 0%
Super Off-Peak: 9 am to 3 pm $43.76 -19%
Winter: October 1 - May 31
Peak: 4 pm to 9 pm $88.49 +23%
Off-Peak: 9 pm to 9 am and 3 pm to 4 pm $72.17 0%
Super Off-Peak: 9 am to 3 pm $51.25 -29%
1. DLAP or Default Load Aggregation Point is the industry name for hourly wholesale electricity prices for the
relevant trading point. In this case, the PG&E delivery point is the appropriate trading node.
The commodity rates for E-1 TOU are developed such that the pricing differentials in Table 3 are
maintained for the energy-related portion of the rate. The commodity costs that are demand-related are
added to the peak commodity rates. Demand-related commodity costs are spread evenly across summer
and winter seasons and applied only to peak commodity rates. Finally, because local capacity costs are
based on peak demand, 72% of these costs occur in summer, while 28% occur in the winter and these
costs are correspondingly included in the summer and winter volumetric rates. Table 4 summarizes the
cost components in each TOU commodity rate.
TABLE 4: TOU RATE DESIGN COST COMPONENTS
Commodity Cost
Component Energy Related Demand Related
Summer Peak 187% of Off Peak Price 72% of Local Capacity Costs
Summer Demand Costs
Summer Off-Peak Marginal Cost Scaled Based on
Embedded Power Costs
(Calculated in COSA)
None
Summer Super-Off Peak 84% of Off Peak Price None
Winter Peak 121% of Off Peak Price 28% of Local Capacity Costs
Winter Demand Costs
Winter Off-Peak Marginal Cost Scaled Based on
Embedded Power Costs
(Calculated in COSA)
None
Winter Super Off-Peak 73% of Off Peak Price None
LOAD CHARACTERISTICS
The billing determinants for each TOU pricing period are estimated from the load profile data obtained
from the HO5 and HO7 feeders. Table 5 summarizes the estimated share of annual energy within each
TOU period. For the average customer using 450 kWh per month (5,400 kWh/year), 31.6% or 1,706 kWh
are consumed in the winter off peak period.
MEMORANDUM
Electric TOU Rate Design E-1
11
TABLE 5: RESIDENTIAL LOAD SHARE BY TOU PERIOD
Share of Annual Energy
Summer: June 1 – September 30
Peak: 4 pm to 9 pm 8.0%
Off-Peak: 9 pm to 9 am and 3 pm to 4 pm 9.2%
Super Off-Peak: 9 am to 3 pm 14.2%
Winter: October 1 - May 31
Peak: 4 pm to 9 pm 15.7%
Off-Peak: 9 pm to 9 am and 3 pm to 4 pm 31.6%
Super Off-Peak: 9 am to 3 pm 21.3%
Table 6 compares the recommended E-1 TOU rate with the standard E-1 rate adjusted for FY2026. The
commodity rates are developed by scaling the marginal costs for the TOU periods (Table 3) so that when
combined with the billing determinants resulting from Table 5, the revenue collected equals the
commodity revenue requirement. The fixed customer charge is the same as the recommended fixed
customer charge for the E-1 class. The distribution costs for FY2026 are estimated at $14.1 million (11%
increase from FY2025 distribution costs). After an 11% increase in the customer charge, the remaining
distribution costs are $12.4 million. This translates to $0.09351/kWh. This distribution rate is the same
between E-1 and E-1-TOU.7 The Public Benefits Charge (PBC) is also the same across time periods and
across the Tiered E-1 rate compared to the E-1-TOU rate.
TABLE 6: RECOMMENDED RESIDENTIAL TOU RATE FY2026
(PRICES PER KWH UNLESS OTHERWISE STATED)
Commodity Distribution PBC Total
E-1
Customer Charge, $/month $5.15
Tier 1 (up to 450 kWh)$0.10373 $0.09593 $0.00604 $0.20569
Tier 2 (> 450 kWh)$0.13372 $0.08968 $0.00604 $0.22944
E-1-TOU
Customer Charge, $/month $5.15
Summer (June 1 to Sept 30)
Peak: 4 pm to 9 pm $0.23354 $0.09351 $0.00604 $0.33309
Off Peak: 9 pm to 9 am and 3 pm to 4 pm $0.08249 $0.09351 $0.00604 $0.18204
Super Off Peak: 9 am to 3 pm $0.06690 $0.09351 $0.00604 $0.16645
Winter (Oct 1 to May 31)
Peak: 4 pm to 9 pm $0.16705 $0.09351 $0.00604 $0.26660
Off Peak: 9 pm to 9 am and 3 pm to 4 pm $0.11033 $0.09351 $0.00604 $0.20988
Super Off Peak: 9 am to 3 pm $0.07835 $0.09351 $0.00604 $0.17790
7 The average distribution rate of $0.09351/kWh is required to recover the $12.4 million in residential class
distribution system costs. The Standard E-1 Rate is based on a tiered rate design which results in the same collection
of $12.4 million in revenues.
MEMORANDUM
Electric TOU Rate Design E-1
12
The FY2026 average annual volumetric rate for both for E-1 and E-1 TOU is $0.21486/kWh. If all residential
customers select the E-1 TOU rate plan, and did not modify behavior, the revenue collected would total
$29.4 million.
BILL IMPACTS
The bill impacts from switching from E-1 to E-1-TOU will depend on the monthly electric use. Higher usage
in any month will make the TOU rate more attractive to customers. Average monthly use is estimated at
450 kWh, the Tier 1 baseline. Table 7 compares residential monthly bills under two rate plans at the same
average monthly use. In every month, the E-1 rate results in a lower bill. The annual difference is $37.96.
This suggests that customers near the average use, and with a usage profile consistent with the feeder
data, should prefer to stay on the E-1 rate unless they plan to change their usage patterns.
TABLE 7: BILL IMPACTS: AVERAGE USE
Month Average Use kWh Bill: E-1-TOU Bill: E-1
Difference
(E-1 TOU bill – E-1 bill)
1 408 $92.05 $89.07 $2.98
2 440 $98.38 $95.66 $2.72
3 385 $86.90 $84.34 $2.56
4 388 $87.81 $84.96 $2.85
5 436 $98.16 $94.83 $3.33
6 438 $98.59 $95.24 $3.35
7 619 $138.83 $136.49 $2.34
8 523 $119.46 $114.46 $5.00
9 523 $117.50 $114.23 $3.27
10 418 $94.52 $91.13 $3.39
11 407 $91.80 $88.87 $2.93
12 417 $93.96 $90.72 $3.24
Total $1,217.96 $1,180.00 $37.96
Table 8 shows the same analysis for the case where 200 kWh per month is added to the 450 kWh/month
usage. It is assumed that this use is due to electrification (such as electric vehicle charging). We assume a
50/50 split between off-peak and super off-peak period usage for the additional kWh. Table 8
demonstrates that for EV charging timed to avoid the peak cost period, the E-1-TOU rate is beneficial,
saving customers approximately $55 per year.
MEMORANDUM
Electric TOU Rate Design E-1
13
TABLE 8: BILL IMPACTS: AVERAGE USE PLUS 200 KWH EV CHARGING
Month Average Use kWh Bill: E-1-TOU Bill: E-1 Difference
1 653 $130.83 $133.96 -$3.14
2 689 $137.16 $141.31 -$4.14
3 627 $125.68 $128.69 -$3.01
4 631 $126.59 $129.37 -$2.78
5 684 $136.94 $140.39 -$3.45
6 687 $133.44 $140.85 -$7.41
7 888 $173.68 $182.38 -$8.69
8 781 $154.31 $160.35 -$6.04
9 781 $152.35 $160.12 -$7.77
10 664 $133.30 $136.26 -$2.96
11 652 $130.58 $133.73 -$3.15
12 663 $132.74 $135.80 -$3.06
Total $1,667.59 $1,723.20 -$55.61
Finally, Table 9 shows a range of potential bill impacts for low, average, and high levels of monthly kWh
use. Even with no changes in behavior to avoid peak cost periods, residential customers with higher use
could potentially reduce their bills by switching to the TOU rate option. The analysis assumes that
customer usage profiles are consistent with the feeder data. Refer back to Table 5 for the share of annual
energy consumption in each seasonal TOU period. This profile is used to calculate monthly bills at different
levels of consumption ranging from 200 kWh/month to 1,600 kWh/month.
TABLE 9: BILL IMPACTS: LOW, AVERAGE, AND HIGH USAGE LEVELS
Bill: E-1 TOU Bill: E-1 Difference
200 kWh $47.96 $46.29 $1.68
450 kWh (Tier 1 Baseline)$101.48 $97.71 $3.77
600 kWh $133.59 $132.13 $1.46
800 kWh $176.41 $178.02 -$1.61
1,600 kWh $347.66 $361.57 -$13.91
September 2, 2025 PaloAlto.gov
Recommend the
City Council Adopt
Voluntary Residential E-1
Time of Use (TOU) Rates
Finance Committee
2
What are Time of Use Rates?
Pricing structure for electricity that varies depending on the
time of day
•Energy is cheaper during off-peak times (like the middle of
the day) when there is solar generation and demand is
lower; energy is more expensive during peak times (like
early evening) when demand is higher
•May encourage people to use electricity during
cheaper/greener times
•Can help reduce demand on electrical grid during peak
times and lead to lower energy bills if customers shift usage
to off-peak hours
3
Residential Electric Time-of-Use Rates (E-1 TOU)
Voluntary opt-in rate plan for separately metered E-1 residential customers
Effective January 1, 2026 to allow sufficient time to prepare for implementation and communication
Provide data on demand and cost for future cost study & rate design
Not yet available to Net Energy Metering (NEM) customers but will be offered to NEM 2 customers once billing
constraints are resolved
TOU rate design
The proposed E-1 TOU rates align with the requirements of Article XIII C of the California Constitution (often
referred to as Proposition 26) to align with the cost of electricity.
The proposed E-1 TOU rates also align with the cost of electricity at the time of use.
Customers have the opportunity for lower-cost and lower carbon intensity off-peak usage (e.g., EV charging or
other electric use)
Proposed E-1 TOU rates
Based on FY 2026 cost estimates
Reflect FY 2024 Cost-of-Service study (most recent) & April 2025 residential TOU supplement
Designed to produce the same revenue as the standard E-1 rates that became effective on July 1, 2025
(assuming no change in usage level & pattern)
4
Proposed E-1 TOU periods & rates: Winter (October-May)
Compared to standard E-1 rate plan (tiered rates; Tier 1 baseline at 450 kWh/month)
Same customer charge of $5.15/month and Public Benefit Charge (PBC)
Variable rates below include Commodity, Distribution and PBC
5
Proposed E-1 TOU periods & rates: Summer (June-September)
Compared to standard E-1 rate plan (tiered rates; Tier 1 baseline at 450 kWh/month)
Same customer charge of $5.15/month and Public Benefit Charge (PBC)
Variable rates below include Commodity, Distribution and PBC
6
Key Factors Considered in Developing TOU Time Periods
1. Marginal Cost of Energy
Highest priced periods typically occur in evening when demand is high and lower cost solar energy
is not available
2. Distribution System Capacity and Peak Demand
Managing peak demand can defer or avoid system investment
System peak demand across all customer classes is between 4pm and 9pm
3. Greenhouse Gas (GHG) Intensity of Market Energy
Marginal cost, peak demand & high GHG content are generally highest during same evening period
Emission intensity data supports third TOU (super off-peak) period from 9am to 3pm that has low
GHG intensity and marginal cost
4. Best Practices in Ratemaking
Customers are more able to shift usage to lower-priced periods when higher-priced period is
shorter in duration
7
Next Steps
Staff plans to present the E-1 TOU rates to the Council in September, including a public hearing
Staff will present implementation and communication plan details to the UAC at October Meeting
Preparation for E-1 TOU launch includes
Modifying billing system to compute E-1 TOU bills using AMI energy consumption data
Developing logistics related to customer enrollment, information tools and communication
Developing measures of program success including measuring rates of enrollment and retention
Will be analyzing customer changes in usage patterns as a result of CPAU’s marginal cost profile
To ensure a smooth roll-out, staff anticipates an initial testing period with a small group of customers
beginning in January 2026, followed by a modulated increase in customer enrollments
8
Recommendation
The Finance Committee recommends that the City Council adopt a resolution:
Adding voluntary Rate Schedule E-1 TOU applicable to separately metered
residential dwellings receiving electric service from the City of Palo Alto Utilities,
effective January 1, 2026